Cng Is A Readily Available Alternative To ________

1. Why Compressed Natural Gas? - Freedom CNG

Why CNG? CNG is a readily available alternative to gasoline that's made by compressing natural gas to less than 1% of its volume at standard atmospheric ...

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2. CNG is a readily available alternative to ______. - CenterStudent

Answer:GasolineExplanation:CNG: compressed natural gas is an alternative to gasoline; it's made by compressing natural gas to less than 1% of its volume at ...
Answer:GasolineExplanation:CNG: compressed natural gas is an alternative to gasoline; it's made by compressing natural gas to less than 1% of its volume at 1atm.

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3. CNG is a readily available alternative to gasoline that's made by ...

Missing: _________. | Show results with:_________.
As gasoline prices continue to rise, American interest in CNG is rising as well, and with good reason – CNG costs about 50% less than gasoline or diesel, emits up to 90% fewer emissions than gasoline and there’s an abundant supply right here in America. So it’s clean, affordable abundant and American. While you’ll see a considerable amount of savings at the pump, the return doesn’t stop there. The benefits of using natural gas goes far beyond gas prices. Unlike gasoline or diesel fuel, natural gas leaves behind little or no residue, which in turn prevents damage to the internals of your engine. Natural gas produces very little carbon content that gives CNG vehicles longer periods of time between tune-ups and oil changes. Most drivers go anywhere from 10,000 to 25,000 miles before needing an oil change.

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4. Natural Gas Basics - Alternative Fuels Data Center - Department of Energy

Missing: readily _________.

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5. cng is a readily available alternative to

6 days ago · CNG is a readily available alternative to petroleum and depending on the vehicle offers a significant reduction in emissions despite being a ...
One of these energy sources only a small step removed from fossil fuels is compressed natural gas (CNG). Compressed natural gas is a readily available alternative to gasoline that’s made by compressing natural gas to less than 1% of its volume at standard atmospheric pressure—basically gasoline is compressed to become more than 100 times …

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6. cng is a readily available alternative to ______.

Aug 30, 2023 · Compressed Natural Gas (CNG) is an abundant clean burning alternative to gasoline and other transportation fuel. CNG is a readily available ...
Posted on 2023-08-30 by admin

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7. [PDF] Propane, CNG, LNG, and Synthetic Fuels - James Halderman

12 When sold as a fuel, propane is also known as. ______ ______. ___ ... 1 ______ ______ ___ is a readily available alternative to gasoline made ...
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___________ Is Not A Common Injury That An Automotive Tech May Experience At Work.Jb Hi Fi Phones
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8. [PDF] Hydrogen/CNG Blended Fuels Performance Testing in a Ford F-150

Because of the availability of CNG vehicles, many energy company and government fleets have adopted CNG as their principle alternative fuel for transportation.
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9. [PDF] department of food and agriculture

May 18, 2016 · Alternative Fuels Data Center. Natural Gas. Natural gas, a domestically produced gaseous fuel, is readily available through the utility.
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10. [PDF] Inspection of Co 1, ressed Natural Gas Cylinders on ichool Buses - NREL

The materials listed below are available free from the National Alternative Fuels Hotline at 800-423-1363. •. Safety First with CNG: An Introduction to CNG ...
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11. [PDF] UC Irvine - eScholarship

have been particularly prolific and flame speed data is readily available. However flame speeds measurements for alternative fuels such as coal derived ...
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12. [PDF] SPECIFICATIONS CONTRACT DOCUMENTS JUNE 17,2013

readily accessible position to the vehicle refueller. This valve shall be ... Standard for Compressed Natural Gas (CNG) Vehicular Fuel. IFC 2208 &3003. Natural ...
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13. [PDF] FTA Motor Fuel Tax Section Uniformity Project

5 days ago · ... Alternative Fuels Report ... (CNG) is typically stored in a tank at a pressure of 3000 to 3600 psi ...
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14. Electricians will sometimes call switches “disconnects” or a ... - Weegy

Jan 3, 2023 · This answer has been confirmed as correct and helpful. CNG is a readily available alternative to ______. A) AntifreezeB) Brake fluidC ...
Electricians will sometimes call ______ “disconnects” or a “disconnecting means.” A) Electrical cordsB) Three-pronged plugsC) Two-pronged plugsD) Switches

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15. [PDF] AGENDA REPORT - Beverly Hills Climate Action & Adaptation Plan

Each proposer may offer its available alternatives and best approach in terms of providing both natural gas pricing and Low Carbon Fuel. Standard (LCFS) ...
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16. 2023 S/P2 Training Automotive Service Safety Final Exam Answers 1

CNG is a readily available alternative to ______. ANSWER: oil. CNG containers need to be inspected ______. ANSWER: After the vehicle is involved in an accident ...
When jump starting a car always remember __________. When jump-starting a car, always remember ___________. A.) Negative to positive, po...

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17. [PDF] EFFECTIVE DATE - PennDOT

Nov 3, 2022 · This SECOND AMENDMENT TO THE CNG FUELING FOR TRANSIT AGENCIES. PARTNERSHIP PROJECT PUBLIC-PRIVATE TRANSPORTATION PARTNERSHIP (this.
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18. [DOC] E/ECE/324/Rev - UNECE

... ______. Addendum 48 – Regulation No. 49. Revision 6 - Amendment 2. Supplement 2 to the ... It shall then be readily available for inspection and the access ...
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À ¶ ¶ NÃ ¶ ¶ ¶ ¶ ¶ e$ e$ Â ¸ ¶ ¶ ¶ ð$ ¶ ¶ ¶ ¶ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ÿÿÿÿ ¢- ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ Ü ü¢ : E / E C E / 3 2 4 / R e v . 1 / A d d . 4 8 / R e v . 6 / A m e n d . 2 "E / E C E / T R A N S / 5 0 5 / R e v . 1 / A d d . 4 8 / R e v . 6 / A m e n d . 2 2 3 J u n e 2 0 1 4 A g r e e m e n t C o n c e r n i n g t h e A d o p t i o n o f U n i f o r m T e c h n i c a l P r e s c r i p t i o n s f o r W h e e l e d V e h i c l e s , E q u i p m e n t a n d P a r t s w h i c h c a n b e F i t t e d a n d / o r b e U s e d o n W h e eled Vehicles and the Conditions for Reciprocal Recognition of Approvals Granted on the Basis of these Prescriptions* (Revision 2, including the amendments which entered into force on 16 October 1995) _________ Addendum 48 Regulation No. 49 Revision 6 - Amendment 2 Supplement 2 to the 06 series of amendments Date of entry into force: 10 June 2014 Uniform provisions concerning the measures to be taken against the emission of gaseous and particulate pollutants from compression-ignition engines and positive ignition engines for use in vehicles _________ UNITED NATIONS Paragraph 2.52., amend to read: "2.52. "Qualified deteriorated component or system (QDC) " means a component or a system that has been intentionally deteriorated such as by accelerated ageing or by having been manipulated in a controlled manner and which has been accepted by the Type Approval Authority according to the provisions set out in Annex 9B to this Regulation for use when demonstrating the OBD performance of the engine system;" Paragraph 3.1.4., add a new subparagraph (i), to read: " (h) Where appropriate, copies of other type approvals with the relevant data to enable extension of approvals and establishment of deterioration factors; (i) Where appropriate, the documentation packages required by this Regulation for the correct installation of the engine type-approved as separate technical unit." Paragraph 4.6.3., amend to read: "4.6.3. In the case of natural gas/biomethane fuelled engines, including dual-fuel engines, the manufacturer shall demonstrate the parent engines capability to adapt to any natural gas/biomethane composition that may occur across the market. This demonstration shall be carried out according to this paragraph and, in case of dual-fuel engines, also according to the additional provisions regarding the fuel adaptation procedure set out in paragraph 6.4. of Annex 15 to this Regulation." Paragraph 4.6.5., amend to read: "4.6.5. In the case of natural gas/biomethane engines, the ratio of the emission results "r" shall be determined for each pollutant as follows: " Paragraph 4.7., amend to read: "4.7. Requirements on restricted fuel range type-approval in case of engines fuelled with natural gas/biomethane or LPG, including dual-fuel engines. Restricted fuel range type approval shall be granted subject to the requirements specified in paragraphs 4.7.1. to 4.7.2.3. below." Paragraph 4.7.1., amend to read: "4.7.1. Exhaust emissions type-approval of an engine running on CNG and laid out for operation on either the range of H-gases or on the range of L-gases." Paragraph 4.7.2.1., amend to read: "4.7.2.1. The parent engine shall meet the emission requirements on the reference fuels GR and G25 in the case of CNG, on the reference fuels GR and G20 in the case of LNG, or on the reference fuels A and B in the case of LPG, as specified in Annex 5 to this Regulation. Fine-tuning of the fuelling system is allowed between the tests. This fine-tuning will consist of a recalibration of the fuelling database, without any alteration to either the basic control strategy or the basic structure of the database. If necessary the exchange of parts that are directly related to the amount of fuel flow such as injector nozzles is allowed." Paragraph 4.7.2.2., amend to read: "4.7.2.2. In the case of CNG, at the manufacturer's request, the engine may be tested on the reference fuels GR and G23, or on the reference fuels G25 and G23, in which case the type-approval is only valid for the H-range or the L-range of gases respectively." Paragraph 4.7.2.3., amend to read: "4.7.2.3. On delivery to the customer the engine shall bear a label as specified in paragraph 4.12.8. below stating for which fuel range composition the engine has been calibrated." Paragraph 4.12.3.3.6., add new subparagraphs (g), (h), and (i) and renumber subparagraphs (g) and (h) (former) as (j) and (k), to read: " (f) HLt in the case of the engine being approved and calibrated for a specific gas composition in either the H-range or the L-range of gases and transformable to another specific gas in either the Hrange or the L-range of gases by fine tuning of the engine fuelling; (g) CNGfr in all other cases where the engine is fuelled with CNG/biomethane and designed for operation on one restricted gas fuel range composition; (h) LNGfr in the cases where the engine is fuelled with LNG and designed for operation on one restricted gas fuel range composition; (i) LPGfr in the cases where the engine is fuelled with LPG and designed for operation on one restricted gas fuel range composit i o n ; ( j ) L N G 2 0 i n c a s e o f t h e e n g i n e b e i n g a p p r o v e d a n d c a l i b r a t e d f o r a s p e c i f i c l i q u e f i e d n a t u r a l g a s / l i q u e f i e d b i o m e t h a n e c o m p o s i t i o n r e s u l t i n g i n a lð- s h i f t f a c t o r n o t d i f f e r i n g b y m o r e t h a n 3 p e r c e n t t h e lð- s h i f t f a c t o r o f t h e G 2 0 g a s s p e c i f i e d i n Annex 5 to this Regulation, and the ethane content of which does not exceed 1.5 per cent; (k) LNG in case of the engine being approved and calibrated for any other liquefied natural gas / liquefied biomethane composition." Insert a new paragraph 4.12.3.4., to read: "4.12.3.4. In addition to the marking on the engine, the approval mark may also be retrievable via the instrument cluster. It shall then be readily available for inspection and the access instructions included in the user manual of the vehicle." Paragraph 4.12.8., amend to read: "4.12.8. Labels for natural gas/biomethane and LPG fuelled engines In the case of natural gas and LPG fuelled engines with a restricted fuel range type-approval, the following labels are applicable:" Paragraph 5.1.4.1., amend to read: "5.1.4.1. The documentation package required by paragraph 3. of this Regulation enabling the Type Approval Authority to evaluate the emission control strategies and the systems on-board the vehicle and engine to ensure the correct operation of NOx control measures, as well as the documentation packages required in Annex 10 (off-cycle emissions), Annexes 9A and 9B (OBD) and Annex 15 to this Regulation (dual-fuel engines), shall be made available in the two following parts: " Paragraph 5.1.4.3., amend to read: "5.1.4.3. The extended documentation package shall include: (a) Information on the operation of all AES and BES, including a description of the parameters that are modified by any AES and the boundary conditions under which the AES operate, and indication of which AES and BES are likely to be active under the conditions of the test procedures set out in Annex 10 to this Regulation; (b) A description of the fuel system control logic, timing strategies and switch points during all modes of operation; (c) A full description of the inducement system required in Annex 11 to this Regulation, including the associated monitoring strategies; (d) The description of the anti-tampering measures considered in paragraph 3.1.4. (b) and in paragraph 3.2.4. (a) of this Regulation." Add a new paragraph 5.2.4., to read: "5.2.4. For the dilute testing of positive ignition engines by using an exhaust dilution system, it is permitted to use analyser systems that meet the general requirements and calibration procedures of Regulation No. 83. In this case, the provisions of paragraph 9. and Appendix 2 to Annex 4 to this Regulation shall not apply. However, the test procedures in paragraph 7. of Annex 4 to this Regulation and the emission calculations provided in paragraph 8. of Annex 4 shall apply." Paragraph 5.3., Table 1 and notes, amend to read: "5.3. Emission limits Table 1 provides the emissions limits that apply to this Regulation. Table 1 Emission limits Limit valuesCO (mg/kWh)THC (mg/kWh)NMHC (mg/kWh)CH4 (mg/kWh)NOX* (mg/kWh)NH3 (ppm)PM mass (mg/kWh)PM number (#/kWh)WHSC (CI)1,50013040010108.0 x 1011WHTC (CI)4,00016046010106.0 x 1011**WHTC (PI)4,00016050046010106.0 x 1011**Notes: PI Positive Ignition CI Compression Ignition * The admissible level of NO2 component in the NOX limit value may be defined at a later stage. ** The limit shall apply as from the dates set out in row B of Table 1 in Appendix 9 to Annex 1 to this Regulation. " Paragraph 6.2., split into 6.2. and 6.2.1. and amend to read: "6.2. Installation of a type-approved engine on a vehicle 6.2.1. The installation of an engine type-approved as a separate technical unit on a vehicle shall, in addition, comply with the following requirements: (a) As regard to the compliance of the OBD system, the installation shall, according to Appendix 1 to Annex 9B to this Regulation, meet the manufacturer's installation requirements as specified in Part 1 of Annex 1; (b) As regard to the compliance of the system ensuring the correct operation of NOx control measures, the installation shall, according to Appendix 4 to Annex 11 to this Regulation, meet the manufacturer's installation requirements as specified in Part 1 of Annex 1 to this Regulation; (c) The installation of a dual-fuel engine type-approved as a separate technical unit on a vehicle shall, in addition, meet the specific installation requirements and the manufacturer's installation requirements set out in Annex 15 to this Regulation." Paragraph 6.2.1. (former), delete. Paragraphs 8.3.3.3. and 8.3.3.4., amend to read: "8.3.3.3. For diesel, ethanol (ED95), petrol, E85, LNG20, LNG and LPG fuelled, including dual-fuel, engines, all these tests may be conducted with the applicable market fuels. However, at the manufacturers request, the reference fuels described in Annex 5 to this Regulation may be used. This implies tests, as described in paragraph 4. of this Regulation. 8.3.3.4. For CNG engines, including dual-fuel engines, all these tests may be conducted with market fuel in the following way: " Paragraph 8.3.3.5., amend to read: "8.3.3.5. Non-compliance of gas and dual-fuel engines In the case of dispute caused by the non-compliance of gas fuelled engines, including dual-fuel engines, when using a market fuel, the tests shall be performed with each reference fuel on which the parent engine has been tested, and, at the request of the manufacturer, with the possible additional third fuel, as referred to in paragraphs 4.6.4.1. and 4.7.1.2. of this Regulation, on which the parent engine may have been tested. When applicable, the result shall be converted by a calculation, applying the relevant factors "r", "ra" or "rb" as described in paragraphs 4.6.5., 4.6.6.1. and 4.7.1.3. of this Regulation. If r, ra or rb are less than 1, no correction shall take place. The measured results and, when applicable, the calculated results shall demonstrate that the engine meets the limit values with all relevant fuels (for example fuels 1, 2 and, if applicable, the third fuel in the case of natural gas engines, and fuels A and B in the case of LPG engines)." Paragraphs 8.4.1., 8.4.2., and 8.4.3., amend to read: "8.4.1. An engine shall be randomly taken from series production and subjected to the tests described in Annex 9B and in the case of dual-fuel engines to the additional tests required by paragraph 7. of Annex 15 to this Regulation. The tests may be carried out on an engine that has been run-in up to a maximum of 125 hours. 8.4.2. The production is deemed to conform if this engine meets the requirements of the tests described in Annex 9B to this Regulation and in the case of dual-fuel engines to the additional tests required by paragraph 7. of Annex 15 to this Regulation. 8.4.3. If the engine taken from the series production does not satisfy the requirements of paragraph 8.4.1. above, a further random sample of four engines shall be taken from the series production and subjected to the tests described in Annex 9B and in the case of dual-fuel engines to the additional tests required by paragraph 7. of Annex 15 to this Regulation. The tests may be carried out on engines that have been run-in, up to a maximum of 125 hours." Paragraphs 13.3.2. and 13.3.3. amend to read "13.3.2. As from 1 September 2015, type-approvals granted to this Regulation as amended by the 06 series of amendments, which do not comply with the requirement of paragraph 13.2.2. above, shall cease to be valid. 13.3.3. As from 31 December 2016, type-approvals granted to this Regulation as amended by the 06 series of amendments, which do not comply with the requirements of paragraph 13.2.3. above, shall cease to be valid." Annex 1, Table in Part 1, amend to read: " 3.2.1.1.1.Type of dual-fuel engine: Type 1A/Type 1B/Type 2A/Type 2B/Type 3B1,14 3.2.1.1.2.Gas Energy Ratio over the hot part of the WHTC test-cycle: .%143.2.1.6.2.Idle on Diesel: yes/no 1,143.2.2.2.Heavy duty vehicles Diesel/Petrol/LPG/NG-H/NG-L/NG-HL/Ethanol (ED95)/ Ethanol (E85)/LNG/LNG201,153.2.9.3.Maximum allowable exhaust back pressure at rated engine speed and at 100 % load (compression ignition engines only) (kPa)73.2.9.7.1.Acceptable exhaust system volume (vehicle and engine system): (dm³)3.2.9.7.2.Volume of the exhaust system that is part of the engine system: dm3 3.2.12.2.7.0.5.When appropriate, manufacturer reference of the Documentation for installing in a vehicle an OBD equipped engine system3.2.12.2.8.1.Systems to ensure the correct operation of NOx control measures3.2.12.2.8.2.Driver inducement system3.2.12.2.8.2.1.Engine with permanent deactivation of the driver inducement, for use by the rescue services or in vehicles designed and constructed for use by the armed services, civil defence, fire services and forces responsible for maintaining public order: Yes/No1 3.2.12.2.8.2.2.Activation of the creep mode 'disable after restart'/'disable after fuelling'/'disable after parking'1,73.2.12.2.8.3.Number of OBD engine families within the engine family considered when ensuring the correct operation of NOx control measures3.2.12.2.8.3.1.List of the OBD engine families within the engine family considered when ensuring the correct operation of NOx control measures (when applicable)OBD engine family 1: . OBD engine family 2: . etc3.2.12.2.8.3.2.Reference number of the OBD engine family considered when ensuring the correct operation of NOX control measures the parent engine / the engine member belongs to3.2.12.2.8.6.Lowest concentration of the active ingredient present in the reagent that does not activate the warning system (CDmin) (% vol)3.2.12.2.8.8.5.Heated/non-heated reagent tank and dosing system (see point 2.4 of Annex 11)3.2.17.Specific information related to gas and dual fuel engines for heavy-duty vehicles (in the case of systems laid out in a different manner, supply equivalent information) (if applicable)3.2.17.9.When appropriate, manufacturer reference of the documentation for installing the dual-fuel engine in a vehicle143.5.4.CO2 emissions for heavy duty engines3.5.4.1.CO2 mass emissions WHSC test16: (g/kWh)3.5.4.2.CO2 mass emissions WHSC test in diesel mode17: g/kWh3.5.4.3.CO2 mass emissions WHSC test in dual-fuel mode14 (if applicable): g/kWh3.5.4.4.CO2 mass emissions WHTC test16: (g/kWh)3.5.4.5.CO2 mass emissions WHTC test in diesel mode17: g/kWh3.5.4.6.CO2 mass emissions WHTC test in dual-fuel mode14 g/kWh3.5.5.Fuel consumption for heavy duty engines3.5.5.1.Fuel consumption WHSC test16: (g/kWh)3.5.5.2.Fuel consumption WHSC test in diesel mode17: g/kWh3.5.5.3.Fuel consumption WHSC test in dual-fuel mode14: g/kWh3.5.5.4.Fuel consumption WHTC test5,16: (g/kWh)3.5.5.5.Fuel consumption WHTC test in diesel mode13: g/kWh3.5.5.6.Fuel consumption WHTC test in dual-fuel mode 14: g/kWh" Table in Part 2, amend to read: " 3.2.2.4.1.Dual-fuel vehicle: yes/no13.2.9.7.Complete exhaust system volume (vehicle and engine system) (dm³)3.2.9.7.1.Acceptable exhaust system volume (vehicle and engine system) . dm³3.2.12.2.7.On-board-diagnostic (OBD) system3.2.12.2.7.8.OBD components on-board the vehicle3.2.12.2.7.8.0.Alternative approval as defined in paragraph 2.4. of Annex 9A of this Regulation used: Yes/No13.2.12.2.7.8.1.OBD components on-board the vehicle 3.2.12.2.7.8.2.When appropriate, manufacturer reference of the documentation package related to the installation on the vehicle of the OBD system of an approved engine3.2.12.2.7.8.3.Written description and/or drawing of the MI103.2.12.2.7.8.4.Written description and/or drawing of the OBD off-board communication interface103.2.12.2.7.8.5.OBD Communication protocol standard:43.2.12.2.8.1.Systems to ensure the correct operation of NOx control measures3.2.12.2.8.2.Driver inducement system3.2.12.2.8.2.1.Engine with permanent deactivation of the driver inducement, for use by the rescue services or in vehicles designed and constructed for use by the armed services, civil defence, fire services and forces responsible for maintaining public order: Yes/No13.2.12.2.8.2.2.Activation of the creep mode 'disable after restart'/'disable after fuelling'/'disable after parking'1,7...3.2.12.2.8.8.Components on-board the vehicle of the systems ensuring the correct operation of NOX control measures 3.2.12.2.8.8.1.List of components on-board the vehicle of the systems ensuring the correct operation of NOX control measures3.2.12.2.8.8.2.When appropriate, manufacturer reference of the documentation package related to the installation on the vehicle of the system ensuring the correct operation of NOX control measures of an approved engine3.2.12.2.8.8.3.Written description and/or drawing of the warning signal103.2.12.2.8.8.5.Heated/non-heated reagent tank and dosing system (see point 2.4 of Annex 11)" Notes following the table in Part 2, amend to read: " 13 Dual fuel engines. 14 In case of a dual-fuel engine or vehicle (types as defined in Annex 15 to this Regulation). 15 In case of a dual-fuel engine or vehicle, the type of gaseous fuel used in dual-fuel mode shall not be struck out. 16 Except for dual-fuel engines or vehicles (types as defined in Annex 15 to this Regulation). 17 In the case of Type 1B, Type 2B, and Type 3B of dual-fuel engines (types as defined in Annex 15)." Appendix to Information document, Paragraph 5.1., amend to read (including the new footnote and deleting the footnote *): "5.1. Engine test speeds for emissions test according to Annex 42, to this Regulation ______________________ In the case of dual-fuel engines of Type 1B, Type 2B, and Type 3B, types as defined in Annex 15, repeat the information in both dual-fuel and diesel mode." Paragraph 5.1.1., delete (including the footnotes * and **). Paragraph 5.2., amend to read: "5.2. Declared values for power test according to Regulation No. 85 or declared values for power test in dual-fuel mode according to Regulation No. 85. " Paragraphs 5.2.6. to 5.2.6.5., shall be deleted (including the footnotes * and **). Annexes 2A and 2C, Addendum to Type-approval Communication, Paragraphs 1.1.5. and 1.1.5.1., amend to read (including the new footnote and deleting the footnote *): "1.1.5. Category of engine: Diesel/Petrol/LPG/NG-H/NG-L/NG-HL/Ethanol (ED95)/ Ethanol (E85)/LNG/LNG201 1.1.5.1. Type of dual-fuel engine: Type 1A/Type 1B/Type 2A/Type 2B/Type 3B1, ______________________ Dual fuel engines." Paragraph 1.4., amend to read: "1.4 Emission levels of the engine/parent engine1 Deterioration Factor (DF): calculated/fixed1 Specify the DF values and the emissions on the WHSC (if applicable) and WHTC tests in the table below." Table 4, amend to read (including new notes *, **, and and deleting the former footnote **): "Table 4 WHSC test WHSC test (if applicable)*,**DF Mult/add1COTHCNMHCNOX PM MassNH3PM Number EmissionsCO (mg/kWh)THC (mg/kWh)NMHCNOX (mg/kWh)PM Mass (mg/kWh)NH3 ppmPM Number (#/kWh)Test result(mg/kWh)Calculated with DF CO2 mass emission: ....g/kWh Fuel consumption: ..g/kWhNotes: * In the case of engines considered in paragraphs 4.6.3. and 4.6.6. of this Regulation, repeat the information for all fuels tested, when applicable. ** In the case of dual-fuel engines of Type 1B, Type 2B, and Type 3B, types as defined in Annex 15 to this Regulation, repeat the information in both dual-fuel and diesel mode. In the cases laid down in Table 1 of Annex 15 to this Regulation for dual-fuel engines, and for positive ignition engines. " Table 5, amend (including new notes *, **, and and deleting the references to the former footnote **) to read: "Table 5 WHTC Test WHTC test*,**DFCOTHCNMHCCH4NOxPM MassNH3PM NumberMult/add1 EmissionsCO (mg/kWh)THC (mg/kWh)NMHC (mg/kWh)CH4 (mg/kWh)NOx (mg/kWh)PM Mass (mg/kWh)NH3 ppmPM Number (#/kWh)Cold start Hot start w/o regeneration Hot start with regeneration(1) kr,u (mult/add) 1 kr,d (mult/add) 1Weighted test result Final test result with DF CO2 mass emission:......g/kWhFuel consumption: ..g/kWhNotes: * In the case of engines considered in paragraphs 4.6.3. and 4.6.6. of this Regulation, repeat the information for all fuels tested, when applicable. ** In the case of dual-fuel engines of Type 1B, Type 2B, and Type 3B, types as defined in Annex 15 to this Regulation , repeat the information in both dual-fuel and diesel mode. In the cases laid down in Table 1 of Annex 15 to this Regulation for dual-fuel engines, and for positive ignition engines." Annex 3, Table 1, amend to read: "Table 1 Letters with reference to requirements of OBD and SCR systems CharacterNOx OTL1PM OTL2Reagent quality and consumptionAdditional OBD monitors3Implementation dates: new typesDate when type approval cease to be validA4Row "phase-in period" of Tables 1 and 2 of Annex 9APerformance monitoring5Phase in6N/ADate of entry into force of 06 series of Regulation No. 4931 August 2015 B4Row "phase-in period" of Tables 1 and 2 of Annex 9ARow "phase-in period" of Table 1 of Annex 9APhase in6N/A1 September 201431 December 2016CRow "general requirements" of Tables 1 and 2 of Annex 9ARow "general requirements" of Table 1 of Annex 9AGeneral7Yes31 December 2015Notes: 1 "NOx OTL" monitoring requirements as set out in Tables 1 and 2 of Annex 9A to this Regulation. 2 "PM OTL" monitoring requirements as set out in Table 1 of Annex 9A to this Regulation. 3 The requirements regarding the plan and implementation of the monitoring techniques according to paragraphs 2.3.1.2. and 2.3.1.2.1. of Annex 9A to this Regulation. 4 During the phase-in period set out in paragraph 4.10.7. of this Regulation, the manufacturer shall be exempted from providing the statement required by paragraph 6.4.1. of Annex 9A to this Regulation. 5 "Performance monitoring" requirements as set out in paragraph 2.3.2.2. of Annex 9A to this Regulation. 6 Reagent quality and consumption "phase-in" requirements as set out in paragraphs 7.1.1.1. and 8.4.1.1. of Annex 11 to this Regulation. 7 Reagent quality and consumption "general" requirements as set out in paragraphs 7.1.1. and 8.4.1. of Annex 11 to this Regulation. " . Annex 4, Paragraph 6.11.1., amend to read: "6.11.1. The pressure in the crankcase shall be measured over the emissions test cycles at an appropriate location. It shall be measured at the dip-stick hole with an inclined-tube manometer. 6.11.1.1. The pressure in the intake manifold shall be measured to within ±1 kPa. 6.11.1.2. The pressure measured in the crankcase shall be measured to within ±0,01 kPa." Annex 6, Paragraph 1.1., amend to read: "1.1. This annex sets out the procedure for measuring carbon monoxide emissions at idling speeds (normal and high) for positive ignition engines installed in vehicles of category M1 with a technically permissible maximum laden mass not exceeding 7.5 tonnes, as well as in vehicles of categories M2 and N1." Insert a new paragraph 1.2., to read: "1.2. This annex does not apply to dual-fuel engines and vehicles." Annex 7, insert a new paragraph 3.3.2.4., to read: "3.3.2.4. The use of market fuels is allowed for conducting the service accumulation schedule. A reference fuel shall be used to carry out the emission test." Annex 8, insert new paragraphs 4.6.6.1. and 4.6.6.2., to read: "4.6.6.1. As an alternative the electrical power to the PEMS system may be supplied by the internal electrical system of the vehicle as long as the power demand for the test equipment does not increase the output from the engine by more than 1 per cent of its maximum power and measures are taken to prevent excessive discharge of the battery when the engine is not running or idling. 4.6.6.2. In case of a dispute the results of measurements performed with a PEMS system powered by an external power supply shall prevail over the results acquired according to the alternative method under 4.6.6.1." Annex 8, Paragraph 5.1.2., amend to read: "5.1.2. Torque signal 5.1.2.1. The conformity of the torque signal calculated by the PEMS equipment from the ECU data-stream information required in paragraph 9.4.2.1. of this Regulation shall be verified at full load." Paragraph 5.1.2.1. (former), renumber as 5.1.2.1.1. Insert new paragraph 5.1.2.4., to read: "5.1.2.4. Dual-fuel engines and vehicles shall, in addition, comply with the requirements and exceptions related to the torque correction set out in Annex 15 to this Regulation." Appendix 1, Table 1, note 4, amend to read: "4 The recorded value shall be either (a) the net brake engine torque according to paragraph A.1.2.4.4. of this appendix or (b) the net brake engine torque calculated from the torque values according to paragraph A.1.2.4.4. of this appendix." Paragraph A.1.2.4.4. amend to read: "A.1.2.4.4. Connection with the vehicle ECU A data logger shall be used to record the engine parameters listed in Table 1. This data logger can make use of the Control Area Network (hereinafter CAN) bus of the vehicle to access the ECU data specified in Table 1 of Appendix 5 to Annex 9B and broadcasted on the CAN according to standard protocols such as SAE J1939, J1708 or ISO 15765-4. It may calculate the net brake engine torque or perform unit conversions." Paragraph A.1.2.5.3. amend to read: "A.1.2.5.3. Checking and calibrating the analysers The zero and span calibration and the linearity checks of the analysers shall be performed using calibration gases meeting the requirements of paragraph 9.3.3. of Annex 4 to this Regulation. A linearity check shall have been performed within three months before the actual test." Appendix 2, Paragraph A.2.2.3. amend to read: "A.2.2.3. Sampling of gaseous emissions The sampling probes shall meet the requirements defined in paragraphs A.2.1.2. and A.2.1.3. of Appendix 2 to Annex 4 to this Regulation. The sampling line shall be heated to 190 °C (+/-10 °C)." Annex 9B, Paragraph 4.5., insert an example and amend to read: "4.5. Requirements for malfunction classification If a malfunction would result in a different classification for different regulated pollutant emissions or for its impact on other monitoring capability, the malfunction shall be assigned to the class that takes precedence in the discriminatory display strategy (for example Class A takes precedence over Class B1). " Paragraph 4.5.1., amend to read: "4.5.1. Class A malfunction A malfunction shall be identified as Class A when the relevant OBD threshold limits (OTLs) are assumed to be exceeded. The emissions may still remain below the OTLs when this class of malfunction occurs." Paragraph 4.7.1.5.1., amend to read: "4.7.1.5.1. The manufacturer may request, subject to approval by the Type Approval Authority, the ready status for a monitor to be set to indicate "complete" without the monitor having run and concluded the presence or the absence of the failure relevant to that monitor. Such a request may only be approved if during a multiple number of operating sequences (minimum 9 operating sequences or 72 operation hours): Monitoring is temporarily disabled according to paragraph 5.2. of this annex due to the continued presence of extreme operating conditions (e.g. cold ambient temperatures, high altitudes); or The system that is monitored is not in operation and the DTC associated to that system does not have the confirmed and active or the previously active status at the time when the readiness status becomes incomplete during a repair. Any such request must specify the conditions for monitoring system disablement and the number of operating sequences that would pass without monitor completion before ready status would be indicated as "complete". The extreme ambient or altitude conditions considered in the manufacturer's request shall never be less severe than the conditions specified by this annex for temporary disablement of the OBD system." Paragraph 5.2.2., insert a new subparagraph (e) to read: "5.2.2. Ambient temperature and altitude conditions Manufacturers may request approval to disable OBD system monitors: (d) At elevations above 2,500 meters above sea level; or (e) Below 400 meters under sea level; or (f) With the exception of electrical circuit failures, at ambient temperatures below 251 K (-22 degrees Celsius)." Appendix 3, Item 1, amend to read: "Appendix 3 - Item 1 Wherever a feedback control loop exists, the OBD system shall monitor the system's ability to maintain feedback control as designed (possible errors are for example: not entering feedback control within a manufacturer specified time interval, or: when feedback control has used up all the adjustment capability allowed by the manufacturer and the system cannot achieve the target) - component monitoring. " Item 2, amend to read: "Appendix 3 - Item 2 (c1) DPF filtering performance: the filtering and regeneration process of the DPF. This requirement would apply to PM emissions only - emission threshold monitoring. " Item 3, amend to read: "Appendix 3 - Item 3 (b) Active/intrusive reagent: the proper consumption of the reagent if a reagent other than fuel is used (e.g. urea) - performance monitoring; " Appendix 5, Table 1, amend to read (also adding new lines): "Table 1 Mandatory requirements Freeze frameData streamCalculated load (engine torque as a percentage of maximum torque available at the current engine speed)xxEngine speedxxEngine coolant temperature (or equivalent)xxBarometric pressure (directly measured or estimated)xxReference maximum engine torque xNet brake engine torque (as a percentage of reference maximum engine torque), or Actual engine torque / indicated torque (as a percentage of reference maximum engine torque, e.g. calculated from commanded injection fuel quantity)xFriction torque (as a percentage of reference maximum engine torque)xEngine fuel flowx" Table 2, amend to read (deleting one line): "Table 2 Optional engine speed and load information Freeze frameData streamDrivers demand engine torque (as a percentage of maximum engine torque)xxActual engine torque (calculated as a percentage of maximum engine torque, e.g. calculated from commanded injection fuel quantity)xReference maximum engine torque as a function of engine speedxTime elapsed since engine startxx" Annex 9C, Paragraph 4.1.1., amend to read: "4.1.1. Groups of monitors Manufacturers are not required to implement software algorithms in the OBD system to individually track and report in-use performance data of monitors running continuously as defined in paragraph 4.2.3. of Annex 9B to this Regulation." Annex 10, Paragraph 11., amend to read: "11. Documentation The Type Approval Authority shall require that the manufacturer provides a documentation package. This should describe any element of design and emission control strategy of the engine system and the means by which it controls its output variables, whether that control is direct or indirect. The information shall include a full description of the emission control strategy. In addition, this could include information on the operation of all AES and BES, including a description of the parameters that are modified by any AES and the boundary conditions under which the AES operate, and indication of which AES and BES are likely to be active under the conditions of the test procedures in this annex. This documentation package shall be provided according to the provisions of paragraph 5.1.4.3. of this Regulation." Annex 11, Paragraph 5.3., add a reference to footnote 2 and the footnote 2 to read: "5.3. Low-level inducement system The low-level inducement system shall reduce the maximum available engine torque across the engine speed range by 25 per cent between the peak torque speed and the governor breakpoint as described in Appendix 3 to this annex. The maximum available reduced engine torque below the peak torque speed of the engine before imposition of the torque reduction shall not exceed the reduced torque at that speed. The low-level inducement system shall be activated when the vehicle becomes stationary2 for the first time after the conditions specified in paragraphs 6.3., 7.3., 8.5. and 9.4. below, have occurred. ______________________ 2 A vehicle shall be considered as stationary at the latest 1 minute after the vehicle speed has been reduced to zero km/h. The engagement of any device such as a park-brake, a trailer-brake, or a hand-brake shall not be necessary for being stationary." Paragraph 5.4.4., add a reference to footnote 2 and amend to read: "5.4.4. A "disable on time limit" system shall limit the vehicle speed to 20 km/h ("creep mode") on the first occasion when the vehicle becomes stationary2 after eight hours of engine operation if none of the systems described in paragraphs 5.4.1. to 5.4.3. above has been previously been activated." Paragraph 7.1.1.1., amend to read: "7.1.1.1. During the phase-in period specified in paragraph 4.10.7. of this Regulation and upon request of the manufacturer for the purpose of paragraph 7.1. the reference to the NOx emission limit specified in paragraph 5.3. of this Regulation shall be replaced by the value of 900 mg/kWh." Appendix 5, Paragraph A.5.3.1., amend to read: "A.5.3.1. The "NOx control information" shall contain at least the following information: (g) The DTCs associated with the malfunctions relevant to this annex and when their status is 'potential' or 'confirmed and active'." Appendix 6, Paragraph A.6.1., amend to read: "A.6.1. The manufacturer shall demonstrate the correct value of the minimum acceptable reagent quality CDmin during type approval by performing the hot part of the WHTC cycle, in accordance with the provisions of Annex 4 to this Regulation, using a reagent with the concentration CDmin." Annex 15, the title, amend to read: "Additional technical requirements for diesel-gas dual-fuel engines and vehicles" Paragraph 4.3.1.2., amend to read: "4.3.1.2. The dual-fuel mode indicator shall be set for at least one minute on dual-fuel mode or diesel mode as soon as the engine operating mode is changed from diesel to dual-fuel mode or vice-versa. This indication is also required for at least one minute at key-on, or at the request of the manufacturer at engine cranking. The indication shall also be given upon the drivers request." Paragraph 5.4., amend to read: "5.4. Conformity factors In principle, the emission limit applicable for applying the conformity factor used when performing a PEMS test, whether a PEMS test at certification or a PEMS test when checking and demonstrating the conformity of in-service engines and vehicles, should be determined on the basis of the actual GER calculated from the fuel consumption measured over the on-road test. However, in absence of a robust way to measure the gas or the diesel fuel consumption, the manufacturer is allowed to use the GERWHTC determined on the hot part of the WHTC and calculated according to this annex." * Former title of the Agreement: Agreement Concerning the Adoption of Uniform Conditions of Approval and Reciprocal Recognition of Approval for Motor Vehicle Equipment and Parts, done at Geneva on 20 March 1958. E/ECE/324/Rev.1/Add.48/Rev.6/Amend.2E/ECE/TRANS/505/Rev.1/Add.48/Rev.6/Amend.2 E/ECE/324/Rev.1/Add.48/Rev.6/Amend.2E/ECE/TRANS/505/Rev.1/Add.48/Rev.6/Amend.2 PAGE \* MERGEFORMAT 18 PAGE \* MERGEFORMAT 17 " * . 8 : < H J L N j ¢ ¤ ¦ ¨ ª ¬ ® ° Ä Æ È à ä È Ê ê ì t u É Ò Þ à ñ ò ô ÷ üóüïüïüëüçëüóüïëïëàüÜÕÜçÑÍÑÉÜÂ¹²®²®² Âüïüïüëçë h§#Ö @þÿ hM hncd h' hÇÇ h] hÇÇ 0J 5CJ H* hÖê h¾oj hÇÇ hÄsñ hÇÇ 0J&

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19. [PDF] Evaluation of the environmental impact of modem passenger cars ...

For LPG and CNG the selection was aiming at the most modern systems available. ... shortcomings may more readily be expected concerniiigNO and PM. The checks.
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20. [PDF] Uniform Laws and Regulations in the Areas of Legal Metrology and Fuel ...

... alternatives are available: (a) ... in a printed or online telephone directory, or any readily accessible, widely published and publicly available resource.
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21. [PDF] The Transition to Alternative Fuel Vehicles (AFVs) - CORE

The Greater Los Angeles area, though, currently has one of the most mature publicly available CNG refueling infrastructures in the country and the largest ...
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22. [PDF] TAP-CMAQ-Guidebook-Complete ...

Proof of readily available ROW will receive higher scoring in the selection ... Alternative Fuel and Clean Vehicle project, includes EV and CNG Fuel Stations, ...
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23. [PDF] ENERGY POLICY FOR PENNSYLVANIA

alternative fuels available to the public as well as to the State fleet. ... candidates for the use of alternative fuels, such as compressed natural gas (CNG).
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24. [PDF] Interconnect Guide for Renewable Natural Gas (RNG) in New York State

available history and experience. Even ... 18 Biological constituent testing may be precluded by incorporating a filter 0.2 micron filter or as an alternative ...
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25. multi-page.txt - World Bank Documents and Reports

... readily available in other markets if not in Korea. Certain cogeneration and ... 2.44 The alternative technological options available to KEPCO for future ...
Report No. 8142-KO Korea Gas Utilization Study January 23, 1990 Industry and Energy Division Country Department If Asia Regional Office FOR OFFICIAL USE ONLY Document of the World Bank This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without VWorld Bank authorization. CURRENCY EQUIVALENTS Currency Unit - Won (W) US$1.00 - W660 W1,000 - US$1.52 $ in this report refers to the US$ FISCAL YEAR January 1 - December 31 UNITS AND EQUIVALENTS bbl barrel bcm billion cubic meter Btu British thermal unit kw kilowatt kwh kilowatt-hours kcal kilocalories (- 3.968 Btu) Gcal gigacalories (million kcal) KW megawatt (1,000 kW) ppm parts per million Pyong - 3.3 sq. meters toe ton of oil equivalent (- 9.718 GCal) tpy ton per year Twh terawatt-hours (billion kwh) ABBREVIATIONS CGA City Gas Association CHP Combined heat and power (generatior.) HFO Heavy Fuel Oil IGCC Integrated gasification combined-cycle (systems) KDHC Korea District Heating Corporation KEEI Korea Energy Economics Institute KEMCO Korea Energy Management Corporation KEPCO Korea Electric Power Corporation KGC Korea Gas Corporation KGSC Korea Gas Safety Corporation LHV Low Heating Value LNG Liquefied Natural Gas LPG Liquefied Petroleum Gas MOER Ministry of Energy and Resources NPV Net Present Value O&M Operation and maintenance SO2 Sulfur dioxide TSP Total suspended particulates KOOREA GAS UTIUZATION STUDY Table of Contents SUMHARY AND CONCLUSIONS . . . . . . . . . . . . . . . . . . . . . i 1. TEERGY SECTOR . ...................... 1 General. ........................... 1 The Gas Industry . . . . . . . . . . . . . . . . . . . . . . . . 5 Environmental Issues ...................... 11 Energy Price Outloo. . . . . . . . . . . . . . . . . . . . . . . 15 2. GAS UTILIZATION ...... . ................. 22 Introduction ...................... ... . 22 Residevntial, Commercial and Industrial Sectors . . . . . . . . . 25 Gas Utilization for Electric Power Generation . . . . . . . . . . 37 District Heating ............. ..... ..... . 43 Environmental Issues ......... ... .... ... .. . 46 3. SUPPLY-DEKAND SCENARIOS .................... . 53 The Residential, Commercial and Industrial Markets . . . . . . . 54 Demand from the Power Sector .. ........ . 55 Main Infrastructure .... . . . . . . . . . . . . . . . . . . . 59 City Gas Distribution .... . . . . . . . . . . . . . . . . . . 65 Economic Evaluation . . . . . . . . . . . . . . . . . . . . . . . 68 4. INSTITUTIONAL AND POLICY ISSUES ... . . . . . . . . . . . . . . 72 Strategy Formulation and System Planning . . . . . . . . . . . . 73 Environmental Quality and LNG Use ... . . . . . . . . . . . . . 76 Market and Regulatory Issues ... . . . . . . . . . . . . . . . 79 This report was prepared jointly by the World Bank and the Korea Energy Economics Institute (KEEI). Major inputs were also provided by the Korea Gas Corporation. The report was prepared following a Bank mission to Korea in S. ril/May 1989, consisting of Messrs. J-P. Pinard, R. de Silva, S. Khwaja (IBRD), P. Cayrade and R. deLucia (Consultants). The KEEI team was led by Dr. Shin, Shang-Kil. This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. Annexes 1. Energy Balance Forecast . . . . . . . . . . . . . . . . . 81 2. Petroleum Product Price Forecast . . . . . . . . . . . . . 86 3. Schedule of Domestic Petroleum Product Prices . . . . . . . 89 4. Coal Price Projections . . . . . . . . . . . . . . . . . . 90 5. LNG Price Forecast . . . . . . . . . . . . . . . . . . . . 91 6. End-Use Analysis: Residential, Commercial and Industrial Markets .... . . . . . . . . . . . . . . 95 7. Summary of End-Use Analysis at 8X Cost of Capital . . . . . 124 8. Netback Value of Gas in Power Sector. . . . . . . . . . . . 125 9. Gas Demand Scenarios Forecast . . . . . . . . . . . . . . . 129 10. Gas Supply/Demand Programs. . . . . . . . . . . . . . . . . 135 11. Estimate of Investment Cost ............... . 140 12. Net Present Value of Investment Scenarios . . . . . . . . . 150 13. Air Pollution Emissions From Energy Use . . . . . . . . . . 160 Maps IBRD 21915 - Proposed Gas System IBRD 21983R - Proposed Gas System Seoul Metropolitan Area and Vicinities KOREA GAS UTILIZATION STUDY SUMMARY AND CONCLUSIONS 1. Korea's energy endowment is extremely limited and its economy is, as a result, highly dependent on imported energy. Because of the magnitude of the amounts involved -- energy imports in 1988 totalled $5 billion or 10l of total imports -- and related strategic considerations, a central preoccupation of the Government of Korea has been the development of an effective fuel import strategy. In deciding on an appropriate energy mix (essentially a choice between oil products, coal, gas and nuclear energy), the Government is focussing its attention on three critical areas: security of supply, the relative prices of alternative fuels and, increasingly, their environmental impact. 2. In 1981, in the wake of the oil crisis, the Government decided to start importing liquefied natural gas (LNG); actual delivery did not begin until 1987. With LNG now accounting for less than 4X of total primary energy demand, the issue faced by the Government is whether LNG should have a broader role in meeting Korea's long-term energy needs. The present study was undertaken jointly with the Korea Energy Economics Institute (KEEl) and the Korea Gas Corporation (KGC) as an attempt to provide some preliminary answers to this question. Its purpose is to (a) establish the scope for economic use of gas in Korea; (b) assess the viability of alternative investment scenarios in gas infrastructure to meet possible projected demand; (c) outline the possible contribution of gas to a pollution abatement strategy; and (d) review the existing institutional and policy framework and recommend changes needed to meet future growth in gas usage. A. Korean Energy Strategy 3. For a long time, oil from the Middle East was the mainstay of Korea's energy base. However, the oil crisis, and the severe implications this had for Korea's balance of payments, prompted the Government to revise its approach to energy imports. A new .3trategy was developed calling for (a) reducing dependence on petroleum by diversifying into alternative energy sources, including imported coal and LNG, and nuclear energy; (b) selecting a wider spectrum of energy suppliers for oil and other energy imports, and participating in oil ventures overseas to secure supplies; and (c) fostering energy conservation. Korea pursued these policy changes with much success, and dependence on oil imports from the Middle East fell from 1001 in 1978 to less than 60X today, with supplies originating from over twelve countries. - ii - 4. An important facet of this diversification strategy has been the importation of LNG from Indonesia to diversify futel supplies away from imported oil, address environmental concerns particularly in relation to the use of charcoal briquettes for home heating in densely populated areas, and strengthen trading links with Indonesia. The current crntract is for 2 million tons of LNG annually over a 20-year period, now equivalent to 3.6X of Korea's total primary energy needs. However, KEEI's projections of Korea's energy balance envisage that LNG could, by 2010, account for 7.5X of total energy needs (about 10 million tons p.a.). 5. Unlike oil and coal, reliance on LNG requires commicments made well ahead of time because of the long lead time needed for upstream investment in field development and liquefaction facilities. Another critical characteristic of LNG trade is that it translates into a rather expensive gas price in end-use markets because of the high infrastructure costs involved. This issue is aggravated by the fact that Korea is an incipient market for gas and large investments in pipeline reticulation are also required to bring the gas to consumers. On the other hand, natural gas offers much flexibility in use, can be uzilized in highly efficient end-use equipment, and has a relatively benign tmpact on the environment. From these several angles, the import ot LNG thus acquires strategic dimension inasmuch as imports would have to be effected on a sufficient scale to justify the necessary gas infrastructure by bringing down unit costs to a financially attractive level. This would require a concerted decision on the part of the Government, in part motivated by environmental considerations, to make LNG a major fuel source and adopt appropriate pricing and other policies to bring about a sufficient level of usage. 6. KGC was established in 1983 as the government agency responsible for the overall planning and execution of the basic in'rastructure necessitated by the import of LNG (terminal and transmission pipelines). Responsibility for the distribution of gas to the final consumers (except for large-scale users) has been entrusted to private city gas companies. B. Gas Utilization 7. Natural gas is a versatile fuel which can be used for residential and commercial purposes as a cooking fuel or for space heating (and cooling). In industry, gas is used as boiler fuel, in direct heat processes, and as a chemical feedstock. Gas can also be used for power generation. The competitive position of natural gas vis-a-vis other fuels varies widely with the end-use process in which it is applied; it is also considerably affected by the social costs associated with the fuels' relative environmental impact. 8. To delineate the scope for economic use of natural gas in Korea, a comparative analysis was undertaken to assess the economic (and financial) attractiveness of using natural gas as opposed to other fuels in selected - iii - end-uses. This analysis is intended (a) to help build economically consistent gas demand scenarios and estimate the economic value of natural gas in alternative end-uses for the purpose of economic evaluation of required infrastructure investments; (b) to provide a measure of costs involved in using gas rather than a cheaper but more polluting fuel in order to reduce environment-related social costs; and (c) to provide inferene-es regarding sector organization and policy changes (e.g., pricing, introduction of specific technologies) to ensure market penetration in the ,most attractive end-uses. 9. The general conclusion of the analysis is that there is a clear case for gas use in the power sector even without consideratlon of environmental factors. The potential for using gas economically in other (i.e., residential, commercial and industrial) markets is less uniform and requires appropriate qualifications, although attractive end-uses would still add to a substantial demand potential. This potential is considerably enhanced when the environmental advantages offered by natural gas are taken into account. In particular, gas is seen as an economically attractive substitute for HFO and coal in urban areas based on even modest estimates of the social costs of these two fuels. However, fuel ..witching will be hindered by distortions in the pricing system which currently does not reflect the true relative economic cost of alternative fuels, particularly where environmental externalities are concerned. Residential. Commercial and Industrial Markets 10. A series of representative end-use cases sere constructed to examine the competitive position of gas from both the rational (economic) and financial perspectives in the markets normally supplieQ through a distribution network. In each case, natural gas was compared with an array of alternative fuels (e.g., fuel oil, diesel oil, liquefied petroleum gas (LPG), coal or electricity), taking into azcount differentials in equipment efficiency and costs, and other relevant factors. The analysis indicates that LNG-based city gas is economically attractive based on narrowly defined economic criteria (i.e., without consideration of environmental factors) in selected household, commercial, and industrial end-uses, where: (a) competition is against a high economic-cost fuel (at the burner tip), e.g., LPG and in some cases diesel oil; or (b) the user is willing to pay a premium based on the convenience or guality offered by the use of gas (e.g., cookinig, direct heat industrial processes); or (c) gas is used in combination with high-efficiency end-use technologies which are readily available in other markets if not in Korea (e.g., cogeneration and combined heating/cooling technologies). - iv 11. The econsmic attractiveness of natural gas is sensitive to a number of parameters: in the case of large-scale consumers, relative fuel prices are the dominant element, while for the small-end of the market itt terms of fuel consumption (i.e., the resident al and small-commercial markets) the magnitude of distribution and consumer costs becomes predominant. Henne, three factors are of direct relevance in characterizing the range of economic uses of natural gas: (a) the social premium attributed to gas because of its cleanliness; (b) the scope for reducing construction costs, particularly by the city-gas companies; and (c) the introduction of measures designed to improve the availability of gas-firing equipment in Korea, both in terms of volume and performance. 12. Residential Market. !n the residential market, gas use for cooking is motivated by the added convenience it brings to cornsumers compared to bottled LPG. The issue of quality and convenience is very Important as cooking is a consumptive energy use, and therefore fuel preference, and hence "willtngness to pay' (and economic benefit), is strongly influenced by qualitative factors. The question is whether the consumer's preference is such that the additional costs are warranted economically. In the casa of single-dwelling consumers, the distribution costs are high and are apparently not fully covered by the existing tariff which may conceal an element of cross-subsidy. Since an environmentally acceptable alternative exists in the form of LPG, government support to the distribution of gas for cocking in individual housing units does not appear warranted at this stage. Rather, market forces should be left unencumbered to arbitrate between the two fuels. 13. In the more common case of apartment units, unit distribution costs are far lower than for single dwellings and gas distribution for cooking (and water heating) would be justified. However, an alternative hitherto unexplored in Korea exists in the form of LPG delivered in bulk to the apartment building and piped internally to individual apartments. This alternative would be equivalent in convenience and quality with direct access to city gas, while being probably cheaper both in economic and financial terus. We therefore recommend that the technical feasibility of this alternative be investigated. 14. Fuel choice for sRace heating varies both w.th the type of housing and income levels. The traditional Korean heating system operates with anthracite, which is heavily subsidized and, partly for this reason, remains widely used. Single-family dwellings at higher income levels normally rely on modern boilers burning diesel oil, while apartment buildings normally meet their space heating requirements with heavy fuel oil (HFO) in central heating facilities. 15. In the case of individual houses, gas use is attractive economically on a marginal basis (i.e., assuming it would be used for cooking and the latter would justify much of the distribution and connection costs). On a financial basis, however, diesel remains substantially more attractive than gas, which points to the need for a more disaggregated gas tariff structure to better differentiate between cooking loads and the larger space heating loads. 16. Coal-based heating systems provide a distinctly lower standard of convenience than oil- or gas-based systems; however, the scope for fuel switching to pas -- which was one of the original objectives for importing LNG -- is limi ed by the high retrofit costs. While it is still the Government's intent to reduce the incidence of anthracite burning in urban areas for environmental reasons, the coal-based alternative is likely to remain prevalent especially in existing buildings in the absence of regulatory directives and/or financial incentives (para 39). 17. For apartment buildings, one needs to distinguish between central heating facilities, individual heating systems and district heating. While the individual heating system is uncommon in Korea (and is actually barred in more than seven-storey buildings), it would offer the best potential for gas use in the apartment market in the absence of government regulations on the use (or specifications) of fuel oil for central heating. Otherwise, gas-based district heating systems appear to be the most promising option for effective gas use, particularly in the context of a pollution control strategy aimed at reducing the extent of HFO burning in urban areas. District heating, whick was recently introduced in Korea, is based on a centralized heat generating plant supplying urban areas through an insulated steam transmission and distribution network (paras 28-29). 18. Commercial Market. Ine intensity of energy use, which impacts on the scale of gas installations, is the most critical factor in analyzing the scope for gas utilization for commercial space heating where HFO is the fuel normally used. For small-scale commercial consumers, LNG city gas is not competitive with HFO, either in financial or in economic terms, despite a significant difference in boiler efficiency. The impact of gas-related distribution and customer costs, however, is dramatically lessened at larger scale and higher energy consumption levels; thus, for large buildings, HFO and gas are almost equivalent in economic terms (without consideration of environmental impact) although HFO remains much cheaper in financial terms. The comparison actually becomes quite favorable to gas at the high level of consumption typical of large hotels. A comparison with diesel oil is instructive in that it provides a first order, albeit imperfect, approximation of the environmantal gains that could be derived from gas use compared to HFO. This indicates that for the low end of the market diesel use might be the most cost-effective alternative, suggesting that the Government needs to ensure that its fuel-switching directives in favor of gas should be grounded on appropriate economic ranking of available alternatives (para. 38). Restaurant cooking (normally an LPG market) also provides an economically attractive market for natural gas. 19. Irrespective of the intensity of energy use, a direct financial comparison with HFO in the commercial boiler market is har_.y favorable to gas -- and fuel switching in this market segment would normally be posiible only if mandated by the Government as is already done in some areas. However, a number of high-efficiency options, meeting jointly two end-uses, - vi - are now available. These options, which considerably enhance the attractiveness of gas utilization from both economic and financial standpoints, include notably gas-fired absorption technology (meeting both heating and "ooling needs) and internal combustion engine technology (f,r the joint production of heat and electricity). While these options are based on technologies not yet widely marketed in Korea, they should be central to an effective gas utilization strategy. 20. Induetrial Sector. The main advantage of natural gas in industrial applications lies with its ease of use and, in some cases, in its quality as a fuel. Additional benefits result from the lower operation and maintenance costs of energy equipment, and from the fact that reliance on gas eliminates the need for users to carry fuel inventories. Despite these advantages, there are limited prospects for the use of gas as an underboie_r_fuel, except for environmental reasons in densely populated areas. This is partly due to the tact that domestic gas boilers have not yet reached the efficiency standards achieved in more advanced gas markets, and this issue requires government attention. An alternative avenue to induce fuel switching in the industrial 3ector can be found in the cogeneratiog. of heat and electricity which provides much .pportunity for effective use of natural gas. 21. Gas can compete effectively where its quality or some other characteristic is relevant to its end-use, such as in a number of direct heat and drying processes where gas enjoys a clear technical advantage over liquid fuels (because of its clean combustion and better flame quality). A survey of key industries (textiles, metal, food processing, etc) shows that, where this is the case, gas will be the fuel of choice economically although pricing could still be a barrier to the peiietration of these markets. Moreover, gas will be able to make large, and economically rewarding, forays in the industrial fuel market only if supported by an intensive effort in gas technology development. 22. Conclusions. City-gas operations have so far focussed on the cooking, water heating and part of the space heatti,g markets. The analysis indicates that part of the commercial and industrial energy markets also offer attractive opportunities for LNG use (parti'ularly when taking environmiental factors into account as discussed it, paras 37-38). Experience elsewhere has shown that fuel demand by industries is usually characterized by a high price elasticity. In Korea, however, the low price of fuel oil in relation to other fuels, as established by the Government, has so far largely precluded gas penetration of the large boiler fuel market. It is also apparent that switching from HFO boilers to a more sophisticated and efficient use of energy in (gas-fired) cogenerators or advanced heating/cooling systems in large buildings would also be ha7pered by the low price of fuel oil, albeit considerably less so than in the conventional boiler market. Conversion of HFO users to gas has so far occurred mainly on account of fuel use regulations motivated by environmental concerns. Alternative (or supplementary) approaches combining fuel price adjustments (to better reflect true economic costs, including environmental costs) and financial assistance to selected consumers (for equipment financing) need to be developed. In this context, - vii - we also recommend that the Government adopt a more selective approach itl supporting reticulation investment by the city gas companies through subsidized funiding. Efforts should be made to ta,:get financial incentivos zo priority market segments in lieu of the present, largely indiscriminazo approach. The alternative of providing a greater proportion of governmnnt support directly to priority consumers also needs to be investigated. T'lis would allow Government to focus its intervention on those categories of consumers for which the environmental factor is most relevant but where fuel switching is seen to require special incentives, most particularly the residential coal users. 23. The range of equipment and appliances presently available in Kor_a often do not provide the comparative advantages enjoyed by gas-using technologies in well-developed gas markets. Cost reductions, efficiency improvements and access to the most up-to-date technology would affect the competitive position of gas in a major way. No survey of technology availability in Korea has been made to date and this should be an important item in the development of a gas utilization strategy. We recommend thxt such a survey be carried out, leading to a plan of action for the development of appropriate technologies and encouragement to their bronc.er availability in the market place. Gas Utilization for Electric Power Generation 24. Interest in natural gas as a fuel for power generation is keen worldwide due to continued growth in known gas reserves, the cleanliness of gas as a fuel, the debate surrounding nuclear energy and recent improvements in the design and performance of combined-cycle power planta, particularly (although not exclusively) when fired with natural gas. Thcse factors are of particular relevance to Korea's current energy outlook and will have a direct bearing on itE potential use of LNG over the next 10 to 20 years. 25. Combined-cycle plants benefit from low capital costs and relatively short engineering/construction periods, and offer modular deG!gn features that allow utilities to add ge-aerating capability in small increments with short lead-times, thereby minimizing concentration of financial capital and better responding to uncertainties in power demand outlook. Also, gas firing minimizes fuel preparation and handling problems. Finally, recent efficiency improvements in gas turbine technology have significantly enhanced their attractiveness as base-load facilities. 26. Alternative options for future power system expansions in Korea include nuclear plants, coal-fired and oil-fired conventional steam pow.^): plants, and gas- (or diesel oil-) fired combined-cycle plants. A comparison of these alternatives based on the calculation of unit generation costs underscores the economic attractiveness of gas use in f3mbined-cycle plants (when compared to conventional coal-fired steam plants which would be the most logical alternative). Assuming a plant l,ad factor of 66.5X, the netback value of gas at the plant gate is estimate& at - viii - $27/GCal. A direct comparison of the netback value of gas with the expected average cif price of LNG over the period ($17/GCal) points to a potentially large rent available to cover infrastructute costs. This rent, however, is quite sensitive both to load factor and cost of capital assumptions because of the prominence of the capital cost differential factor. A reductior in the cost of capital from 131 (the Government's official figure for planning purposes) to 8X brings the netback value of gas down to $22/GCal (and the rent down from $10/GCal to $/MCal). For the same reason, the competitiveness of gas-fired combined-cycle plants imp-roves significantly at lower load factors. 27. The comparative economics of coal- and gas-fired power generation alternatives will remain primarily dependeut on future commoditv price trends. While present price forecasts (and technological factors) give the gas opt!on a significant advantage (over coal), the o,volution of world demand for each of the two fuels may modify the current relationships. Sinca a gas import strategy (in part predicated on substantial use of gas in the power sector) wcild commit Korea for a long period of time, we propose that the possibility of introducing a partial link between LNG and coal prices (in lieu of the traditional, straight indexation on oil prices) should be explored in the course of future import negotiations as a hedge against unexpected price &aovements. District Heating 28. District heating is particularly well adapted to Korea's climitic conditions and urban environment because of the combination of substat.ial, concentrated, space heating loads and relatively high urban densities. District heating is normally economical only in the context of combined heat and power generation (CHP), where waste heat from electric power generation is used for district heating purposes. Its development is therefore closely linked to that of the power system. The potential for district heating as a cost-effective method to meet urban space heating loads at an acccpraLle environmental cost has improved considerably with thie recent evolution oil combined-cycle technology which -an be easily adapted to a CHP ctinfiguratien. 29. A generic comparison of district heating schemes with traditional space heating methods is hardly feasible because of the multiplicity of site-specific factors. Generally, however, district heating systems are likely to have a eomparative advantage where generating plants can be located reasonably close to the areas to be supplied. District heating planning is still at an early stage. However, given the potentially large- scale use of gas this activity may generate, it is essential that current studies (by KEPCO and the Korea District Heating Corporation (KDHC)) be integrated rapidly within KGC's current gas infrastruc.ure planning exercises. Similarly, the scope for setting up such facilities in other cities, should gas become available there, needs to be explored at an early stage. - ix - Environmental Aspects 30. A comparison of Korea with other industrialized countries suggests that the level, of air pollutants ia quite high, with sulfur dioxide (SO2) and total suopended particulates (TSP) being the most serious sources of air pollution. Despite significant progress since the enactment in 1981 of regulations designed to decrease SO2 concentrations, SO2 levels in Seoul, Pusan and Ulsan still exceed the prescribed annual air quality standards. The Government is committed to a policy of curbing the deterioration of the environment that has resulted from rapid urbanization and industrializa- tion. Natural gas, which is free of most pollutants present in liquid and solid fuels and generates onl- a fraction of the CO2 output of alternative fuels, can play a major role in a pollution control strategy. Accordingly, a key objective of the Government in importing LNG has been to reduce air pollution in urban and highly industrialized areas. 31. For a number of end-uses, the economics of gas utilization are marginal when compared to alternative fuels on a strictly economic basis because of the high cost of LNG. In many such cases, however, differences in environmental impact would considerably strengthen the justification for using natural gas. These include in par.icular substantial portions of the commercial and industrial markets. Issues of concern to the Government should be (a) to determine the extent to which gas use should be encouraged beyond the levels dictated by relative commodity prices and efficiency factors; and (b) to identify the most effective instruments to provide the needed incentives (subsidies for conversion, cross-subsidy in price) and disincentives (taxes on polluting fuels, etc) to facilitate gas penetration of targeted markets. 32. In addressing environmental issues, the Government has so far relied mainly on fuel allocation policies, in particular through the issuance of fuel use regulations specifying minimum fuel quality or altogether barring the use of certain fuels in some areas. While these regulations are well-motivated, the issue is one of cost effectiveness, specifically of the comparative advantage of promoting the use of natural gas to address specific environmental concerns. As environmental issues gain greater prominence in the setting of energy policies, the Government needs to ensure that its gas utilization policies are rooted in an overall pollution control strategy supported by a proper assessment of available alternatives. There are three priority areas where gas can play a critical role in reducing the pollution impact of energy use, although rationalization of government policies will be a prerequisite to the establishment of fuel use patterns that properly account for the relative social costs of each fuel: (a) the use of HFO in the power and industrial sectors; (b) the use of HFO in the urban, commercial sector; (c) the use of anthracite for space heating. 33. Power Sector and Other Large-Scale Users. For large-scale HFO or coal users (large industries and power plants), a number of emission control techniques are available, the most effective methods (flue gas treatment) being able to reduce SO2 and NOx emissior,s by up to 80-90. While such environmental controls assume an increasing proportion of plant costs as regulatory requirements tighten, which would encourage gas use, mandatory fuel switching regulations should be based on a careful analysis of these alternatives. Generally, reliance on market forces to meet specific emission targets should be given preference over administrative fuel use regulations. 34. In the case of the power sector, the availability of technologies able to mitigate the environmental impact of conventional coal- (and oil-) fired p3wer plants may not be sufficient for these plants to gain sufficient public acceptance for KEPCO to implement its proposed expansion program, which calls inter alia for the installation of seven coal plants with a total capacity of 5,100 MW over the next 12 years. A (partial) shift to gas is warranted by the encouraging results of comparative economics. Two factors could over time affect this general recommendation: a drastic change in relative price trends (of LNG and coal) from current expectations; and further progress in power generation technology which is very much in a state of flux in response to environmental concerns worldwide. For these reasons, the Government needs to keep abreast of pro3ress made in the development of various advanced (coal- and oil-firing) power generation technologies, which offer the potential for important environmental gains. These include notably (a) fluidized bed combustion (FBC) systems; and (b) integrated gasification combined-cycle (IGCC) systems. 35. IGCCs provide for the conversion of coal to a highly combustible synthesis gas, composed mainly of carbon monoxide and hydrogen and free of most pollutants, which is then combusted in a combined cycle power plant. IGCC technology is a highly effective way of reducing the SO2 and NOx output of coal-fired stations while taking advantage of combined-cycle efficiency. As such, it probably is the most relevant long-term alternative for Korea and provides a suitable comparison for gas-fired systems for the purpose of long-term system planning on a more or less environmentally equivalent basis. On the basis of current coal gasifier costs and efficiency, the break-even price of gas above which IGCC would become attractive is estimated at about $29/GCal, far above the expected long-term cost of gas (after regasification) -- but close to the netback value of gas against conventional coal plants, which indicates that, as a coal technology, IGCCs would be economically attractive as soon as designs have been scaled up to standard plant sizes. One should expect significant reduction in the costs of coal gasifiers as the technology gains wider acceptance. However, the capital and O&M costs of coal gasifiers would have to drop by as much as 55X for IGCC systems to become attractive for a country like Korea which must import coal as well as gas. Gas-fired combined-cycles are therefore expected to remain the most attractive power generation option for at least the next decade. 36. A separate issue relates to the choice of fuel in existing oil- fired thermal plants. KEPCO has been requested by the Government to convert to continuous gas-firing a number of its oil-fired power plants located in densely populated areas, including the Incheor. plant. However, - xi - the issue of whether this will result in a cost-effective handling of pollution control and LNG load balancing objectives is open to question inasmuch as substantial pollution abatement could stAll be achieved by having these plants occasionally run on low-sulfur fuel oil (to help meet seasonal variations in other markets). Such an approach, which wv.uld reduce the extent of uneconomic use of gas elsewhere (e.g., at Pyeong Taek), could be complemented by a contribution from KFPCO towards the cost of environmental control measures in higher priority areas. We recommend that mandatory fuel-switching policies in the power sector be reviewed to ensure that they provide a cost-effective answer to environmental objectives. 37. Small-scale Energy Consumers. While efficient and relatively cost- effective post-combustion pollution control techniques are available for large power generation and industrial facilities, their costs rapidly become prohibitive as the scale of operations diminishes. Generally speaking, the only options available to reduce the emissions of smaller energy users are to shift to higher quality fuels or to modify the combustion process. 38. The scope for economic use of natural gas in lieu of HFO as a means of mitigating the environmental impact of small- and medium-sized industries (SMIs) and commercial facilities cannot be easily characterized and market forces should be relied on as much as possible to elicit the optimum fuel use pattern. One approach preferable to mandatory fuel switching regulations would be to impose a tax on polluting fuels and strengthen the standards on acceptable fuels. For SMIs, an alternative (or complementary) approach would be to promote the use of gas in the cogeneration of steam and power in CHP facilities, which can achieve environmental as well as efficiency benefits. Cogeneration can be effected either in plant-specific units or in larger-scale facilities designed to supply industrial parks. In either case, natural gas would offer the most attractive fuel. We recommend that suitable institutional arrangements be made to facilitate the establishment of gas-based industrial utilities in areas with large SMI concentrations. The availability of efficient small- scale cogeneration units for commercial and SMI applications also need to be promoted. 39. Residential Consumers. One of the most vexing environmental problems faced by the Government is that of anthracite-burning for residential space heating for which there is no clear economic justification. Gas has clearly a role to play in addre-sing this issue. Aside from a reduction in the extent of subsidies on domestic coal, the most promising avenue would be to encourage fuel switching through financial assistance to consume;s towards the cost of conversion. High efficiency household-sized boilers have been developed, which would minimize retrofit costs and whose availability should be promoted. The development of district heating systems could also provide part of the solution if shown to be feasible in urban areas where traditional habitat is predominant. - xii - C Supply-Demand Scenaios 40. KGC has made preliminary plans to expand the supply of gas in Korea. To evaluate the economic viability of this investment program, alternative supply/demand scenarios were developed based on plausible assumptions about future gas use. For this purpose, the country can conceptually be divided into two separate regions, i.e., the region north of Pyeong Taek (i.e., the Kyongin region), where a gas system is already in place; and the region south of Pyeong Taek (I.e., the Chungchong, Yongnam and Honam regions) where no gas system is as yet available (except for isolated manufactured gas networks). Demand Scenarios 41. Residential. Commercial and Industrial Markets. The basis for our demand scenarios for the residential, commercial and industrial markets is a Gas Demand Study completed by KEEI in 1988. The KEEI demand projections are based on a careful analysis of macroeconomic trends and provide a reasonable starting point for a preliminary review of investments. However, they lack the underpinning of dircrete market surveys, particularly as regards industrial demand. The undertaking of such surveys, together with basic design studies of selected gas, distribution systems, is a critical prerequisite to the implementation of an expanded gas strategy (para. 51). One should also note that the demand scenarios are predicated on the assumption that a policy and institutional framework conducive to the penetration of preferred markets will be put in place as infrastructure construction proceeds (paras 60-62). 42. LNG demand from residential, commercial and industrial consumers in the northern (Kyongin) region is projected to reach 1.0 million tons by 1996 and 2.2 million tons by 2006. Corresponding figures for the rest of the country are 0.5 and 2.2 million tons, respectively. 43. Power Sector. KEPCO's latest power development program provides for the phased erection of a 4x800 MW combined-cycle plant on the island of Il-Do close to Incheon. KEPCO has also made preliminary plans (together with KDHC) for the construction of three gas-fired CHP plants (also based on combined-cycle technology) with total capacity of 775 MW to supply new urban developments in the metropolitan area (i.e., Il-San, Bun Dang and Pyung-Cheon). Since construction of a gas grid to supply the southern part of the country is still under discussion, plans for installing new gas- fired power and CHP capacity outside the area served by the existing gas system are naturally less advanced. However, it would be difficult to justify the construction of a gas grid to the south without a substantial gas-based power-CHP program (para. 54). Given the relevance of power investment decisions in planning future gas infrastructure, uncertainties surrounding power planning, particularly in the southern regions, need to be lifted as soon as possible (para. 58). - xiii - 44. LNG demand from KEPCO in the northern region is projected to reach 3.0 million tons by 1996 and 4.4 million tons by 2006. KGC's current plans do not provide for any use of gas for power generation in the rest of the country. An alternative scenario developped by the mission projects the power sector demand for the whole country to reach 3.5 million tons by 1996 and about 6.0 million tons by 2006. Infrastructure 45. When the decision to import natural gas was made in 1981, the Government initiated a policy of encouraging the development of city gas systems (in the Seoul area and in a few other cities). These systems were to operate initially on manufactured gas as a means of building up markets ahead of the inception of LNG deliveries. The strategy of the Government has been to license private distribution (city gas) companies to establish the needed reticulation. To date, twenty one city gas companies have been licensed to distribute natural gas, seven of which have been converted to LNG in Seoul. 46. Basic Infrastracture. The existing infrastructure consists of an LNG receiving terminal (Pyeong Taek) and of a supply network serving the Seoul metropolitan area. After regasification, LNG is being supplied to the Pyontaek power station and, through the main transmission system, to the Incheon power station and the seven city gas companies licensed to operate in the Seoul metropolitan area for residential, commercial and industrial use. 47. To meet the expected increase in gas demakid, KGC proposes to expand the Pyeong Taek terminal (in two phases) and, in parallel, to construct a new terminal at Incheon. This strategy appears reasonable. In terms of location, siting the second terminal in the south (instead of Incheon) would present advantages in terms of load balancing and would initially reduce investment in transmission pipeline. However, given KEPCO's decision to install a major gas-fired power plant close to Incheon, the construction of a (partially) dedicated terminal at Incheon is logical. A terminal at Incheon would also greatly improve the security of supply for the Seoul area. 48. The program of pipeline construction required to meet the alternative demand scenarios includes (a) reinforcement of the existing system north of Pyeong Taek; and (b) constrvntion of transmission lines south of Pyeong Taek. KGC has undertaken a preliminary concept study of the modifications required to expand the delivery capacity of the existing pipeline system from 2 to 4 million tons of LNG. This complements an earlier feasibility study for a national gas grid to supply tne southern districts. 49. For the purpose of economic analysis, four supply scenarios were developed, covering incrementally the Kyongin, Chungchong, Yongnam and Honam regions. Estimazes of capital costs for each of the four scenarios - xiv - (excluding distribution costs) are $0.93 billion, $1.03 billion, $1.3 billion, and $1.6 billion, respectively. To meet projected demand, rpiticularly from the new combined-cycle plant at Incheon, a first stage extansion of the existing Pyeong Taek terminal would need to be completed hy 1993/94 and the second terminal to come on stream by 1997/98. r:eparation work would therefore need to start soon, including detailed feasibility studies for (a) expansion of the Pyeong Taek terminal and (b) renstruction of a new terminal at Incheon, including a review of access ciannel, soil conditions, etc. 5'. City Gas Distribution. Gas sector planning has so far dealt with !-'a question of gas distribution only incidentally, presumably under the itsumption that private companies supported by cheap government financing could be expected to handle this aspect of sector development efficiently. lowever, the gas companies appear to operate largely under a short-term rlanning horizon and their objectives do not necessarily match those of the rovernment, which are clearly long-term. Thus, the city gas networks are "eing developed without the benefit of long-term plans and are in general roorly adapted to the development of high loads over large areas, thereby iailing to provide a least-cost approach to the sales targets set by the Covernment. 'il. Since the construction costs of utilities in Korea are generally 1-igh compared to those in other countries, possibly due to local factors and regulations, there is a need to take a longer-term view of system evelopment to rationalize tbs use of resources. Distribution costs alone nre expected to amount to $1.1-2.1 billion over the 1990-2006 period (or F5-..OZ of total sector investment on a net present value basis), and will rrobably require a continuation of government support on a significant scale. In view of the magnitude of these investments, we recommend that conceptual master plans, backed up by discrete consumer surveys, be prepared for the largest consumer concentrations, including (a) the Seoul/Incheon area; (b) the Pusan/Ulsan area; (c) a typical medium-density city (possibly Taejon); (d) a typical low-density city. We also recommend that KGC take the lead in executing these studies in close collaboration 'ith the utilities concerned. V onomic Evaluation i7. LNG is presently priced on an FOB basis at about 90X of crude oil, 1 >.iich translates into a few percentage points above crude on a CIF basis 3cause of transport cost differentials. There are indications that, for a .,umber of years, the LNG market will essentially be a buyer's market with a possible softening of prices. However, rather than attempting to forecast che evolution of contract terms over time, our (base case) analysis is predicated on the assumption chat a similar relationship as the one characterizing the existing contract would prevail under future contracts. 53. The proposed investment program, including both KGC's investments in basic infrastructure and those of the gas companies for distribution, - xv - would: (a) increase the average end-use value of the quantities of gas available under the original contract by shifting their usage from existing thermal power plants (where they substitute low-valued HFO) to city gas markets; and (b) expand the overall supply of gas to meet KEPCO's increased demand and broaden the geographical availability of natural gas to the southern regions. 54. Each of the four alternative supply/demand scenarios was measured against the original 1989 situation by calculating the net present value (NPV) of incremental costs and benefits. For each category of consumers, the corresponding (netback) value of gas was used as a measure of benefits. These netback values are based on the economic cost of the energy source being displaced, corrected for differentials in heating value, thermal efficiency, and the capital and operating costs of appliances and end-use equipment. The analysis indicates that Scenario A (Kyongin region only) is clearly attractive with an incremental NPV of about $1.0 billion. Scenario B (Kyongin and Chungchong regions) is an acceptable alternative, with an NPV similar to that of Scenario A. However, Scenarios C and D (Yongnam and Honam regions) would not be viable in the absence of a substantial demand from the power sector, particularly in high-value end- uses (e.g., combined-cycle type of facility, including CHPs). For Scenario C, it is estimated that a minimum of 800 KW of new (combined-cycle) power capacity located in the south, as well as substantial use of gas in existing oil-fired plants, would be required to justify the proposed trunkline investment. Note, however, that the investment could be justified with a lower demand from the power sector if substantial value is attached to the objective of reducing pollution in the highly industrialized Pusan/Ulsan area. 55. We recommend that preparation work start for Scenario B as soon as possible, including (a) detailed feasibility studies for terminal capacity expansion (at Pyeong Taek and Incheon); (b) detailed design of a Pyeong Taek-Taejon pipeline (which could be conceived as a first phase of an eventual trunkline to the south); (c) detailed design for the strengthening of the existing pipeline system north of Pyeong Taek; and (d) conceptual master plans for gas distribution (para. 51). In parallel, detailed analysis of gas demand from the power/CHP sector in the south would need to be undertaken jointly by KGC, KEPCO and KDHC. 56. The economic attractiveness of Scenario D is significantly more marginal than that of Scenario C because of the lower anticipated gas demand in the Honam region. The Government is considering far-reaching regional development plans for the western seaboard, partly through the establishment of new industrial zor.es. These plans could have a significant bearing on future gas demand, particularly if new industrial parks were to be equipped with centralized utility systems which would provide a convenient and economic market for natural gas. We recommend that plans to extend gas distribution to the southwestern part of the country be reviewed after regional development plans have been firmed up and updated forecasts of gas demand are available. - xvi D. Institutional and Policy Issues 57. The analysis indicates that there is clearly a significant role for LNG in the energy sector in Korea based solely on narrowly defined economic criteria. Moreover, taking account of environmental benefits would considerably enhance the potential for economic use of gas. However, the analysis also indicates that gas utilization needs to be carefully charted to ensure that it leads to an efficient use of resources. To be fully effective, decisions on additional imports would need to be accompanied by substantial strengthening of the existing policy and institutional framework to ensure that the combination of market forces with selective government intervention leads to an economicp'iy -fficient LNG consumption pattern. 58. There is first a need to strengthen the interface between power a planning and gas infrastructure planning. The long-term use of gas in power plants will largely dictate the structure of the main gas infrastructure. Details of the pattern of future consumption (e.g., quantities, plant locations, etc.) need to be worked out at an early stage since they will condition such major decisions as the location and timing of future terminals and bulk transmission lines. To bring about greater coordination among the various agencies involved, we recommend that a consultative gas planning working group consisting of representatives of KGC, KEPCO, MOER (and possibly KDHC) should be established. 59. Secondly, there is a need to strengthen the planning capability of | the city gas companies. This could best be done by having the Government prepare a gas distribution master plan for the Seoul metropolitan area as well as the financial and regulatory framework that would make implementation of this plan possible, using the plan as a basis for negotiating long-term supply agreements with the gas utilities. We recommend that KGC take the lead in commissioning such a master plan. 60. Third, a cost-effective gas utilization strategy needs to be defined in the context of a coherent environmental strategy established on the basis of a comparison of alternative air pollution control options. | The Government needs to strengthen its analytical capability in handling these issues. Current regulations on fuel use are apparently based more on administrative ease than careful analysis of economic tradeoffs. Thus, whereas residential anthracite burning is the single largest source of air pollution, government policies have been largely focussed on HFO users and large users of coal (power). A strategy aimed at the anthracite market needs to be developed, possibly involving the use of gas, either by providing assistance .o consumers towards the costs of retrofit, or through the installation of district heating systems in selected areas. More generally, government priorities in the area of urban planning need to be clarified inasmuch as they affect fuel choices. Accordingly, we recommend that the Government establish a working group on energy use in the residential and commercial sectors, which would be in charge of preparing ! - xvil - an "energy zoning Rl j", together with the necessary regulations. Possible use of compressed natural gas (CNG) as a transport fuel also deserves consideration; conversion of city buses wotld be a first priority. 61. Fourth, gas penetration of the most attractive end-uses from an economic standpoint will require careful handling of pricing, equipment financing and regulatory issues. In particular, regulatory interventions such as the introduction of end-use technology efficiency and other standards need examination. Also, uses of alternative market mechanisms to bring financial prices in line with economic prices that reflect some environmental externalities deserve some consideration. 62. Fifth, implementation of an expanded gas strategy will require special efforts to foster the introduction of additional end-use technologies (in particular small-scale, high-efficiency technologies) into the Korean marketplace. A detailed technology supply review is required, leading to an action plan for technology development. We recommend that KGC, through its training and research center, take the lead in this exercise, possibly in collaboration with the Korea Energy Management Corporation (KEMCO) and the Association of Gas Companies. There is also a complementary need to assist end-users adopt these technologies (through financial and technical assistance). E. Conclusion 63. This review of gas utilization prospects indicates that KEEI's and KGC's target of some 10 million tons of LNG to be imported annually by 2010 (or 7.5X of total primary energy in that year) appears reasonable. There is indeed a significant role for LNG as part of both a least-cost energy supply strategy and a least-cost pollution control strategy for Korea. There is a risk however that, because of the magnitude of infrastructure costs involved, government attention would be focussed on investment implementation to the detriment of policy development. There is indeed a complementary need for policy formulation to ensure that an economically efficient LNG consumption pattern and rapid buid-up are achieved to fully justified the proposed investment. Meeting the objectives sketched by KEEI and KGC will require the involvement of a number of entities, both within and without the public sector. To ensure the necessary coordination of all investment planning and policy development activities the Government should establish a clear and comprehensive agenda of actions required of all the parties concerned, as compatible with economic and financial efficiency. 1. THE ENERGY SECTOR A. General 1.1 Korea is almost devoid of indigenous commercial energy resources. Since its Ihigh-growth, industrializing economy is highly energy-intensive - the second highest among major countries in Asia after Japan, it is growing increasingly dependent on imported fuels. Korea's commercial energy endowment consists of hydroelectric power (2,000 NW) and coal (750 million tons). Korea is still able to produce about half the solid fuels it consumes, but coal reserves are becoming depleted and are high cost. Liquid fuels, on the other hand, are wholly imported and dependence on oil import has been kept in check only by a policy of diversifying away from oil. Because of the magnitude of the amounts involved -- energy imports in 1988 totalled $5 billion or lOX of total imports -- and related strategic considerations, a central preoccupation of the Government of Korea (GOK) has been the development of an effective fuel import strategy. Past Developments 1.2 The mainstay of the Korean economy during the 1950s was agriculture; firewood was then the principal energy source. As the destruction of forests during the Korean war led to shortages of fuelwood, energy planners turned vo the development of anthracite coal as an alternative energy supply. During the 1960s, a stable source of energy beyond domestic coal became needed as industrial development picked up and plans were made for the construction of power plants and oil refineries based on imported oil. 1.3 The following decade saw a sharp increase in imports of petroleum fuels, which made the Korean economy increasingly vulnerable to price fluctuations in the international market although supplies remained abundant and dependence on imported oil was not perceived as a source of concern. The oil crisis during the 1970s, however, caused a severe recession and large balance of payment deficits, with Korea having to borrow heavily to meet its Increased oil import bills. These developments prompted the (overnment, in the early 1980s, to revise its approach to energy imports. A new strategy was developed calling for (a) reducing dependence on petroleum by diversifying into alternative energy sources, including imported coal and liquefied natural gas (LNG) and nuclear energy; (b) selecting a wider spectrum of energy suppliers for oil and other energy imports, and participating in oil ventures overseas to secure supplies; e.nd (c) tostering energy conservation partly through industrial restructuring. 1.4 Korea pursued these policy changes with much success. On the supply side, heavy investments were made in nuclear energy. As of end- 1988, total installed nuclear capacity was 6,666 MW with 9 units in operation. To divei-stfy and secure sources of oil supply, Korea has also entered into joint-verture exploration agreements overseas with foreign oil - 2 - companies. Exploration in Korea's offshore areas by the Korea Petroleum Development Corporation (PEDCO) has recently led to the discovery of apparently significant gas deposits east of Pusan (earlier gas shows off the southern coast proved disappointing). These deposits are being further investigated to ascertain the possibility of commercial development. 1.5 Korea also diversified its sources of oil supply. Oil imports have been gradually shifted from long-term contract to spot market purchase. Consequently, dependence on the Middle East fell from 100% in 1978 to less than 60% today, with supplies originating from over twelve countries. Import of LNG from Indonesia, which started in 1987, has been another important facet of this diversification strategy. 1.6 On the demand side, the energy intensity of the economy was reduced partly through efficiency gains in the use of energy and partly through a reduction in che relative share of energy-intensive industries to the advantage of light manufacturing. The energy elasticity of GDP growth is currently close to one, although it was much higher in the 1960s and 1970s when heavy industries were expanding, and well below one in the early 1980s when the emphasis shifted to higher technology manufacturing. Energy Balance 1.7 Korea's total primary energy consumption in 1988 amounted to about 75 million tons of oil equivalent (toe). Of these quantities, domestic production, including hydro and nuclear power and anthracite, accounted for 31% (23 million toe). Oil consumption during the year was 251 million barrels (35 million toe). Imported LNG accounted for another 2.7 million toe or 3.6% of total primary energy demand. Petroleum 1.8 Crude oil imports in 1988 accounted for 86% of total petroleum imports, which indicates that the structure of the domestic refinery industry is relatively in line with the pattern of demand although historical data show a slight reduction in self-sufficiency. Imported products included LPG (15 million bbl), diesel oil (8 million bbl) and heavy fuel oil (HFO) (11 million bbl). Coa' 1.9 Korea is the second largest coal importer in the x7orld (after Japan). It imports its coal from Australia (40X), South Africa (25%), Canada (16%) and the United States (141). Total imports amounted to 24 million tons in 1988 (15 million toe). Use of coal in the power sector (9 million tons or 19% of total coal consumption) is expected to quadruple over the next 12 years. Domestic anthracite, which is used mostly in the fabrication of briquettes for space heating, is the main source of energy for an estimated 7.5 million, mostly low-income households. Anthracite production, which benefits from protection against cheaper imports, has remained so far stable at about 25 million tons (12 million toe). The - 3 - Government is presently investigating ways of encouraging the abandonment of uneconomic mines, including compensation to industries and re-employment programs for workers. Anthracite production is expected to decline from 26 million tons (12 million toe) in 1988 to less than half this amount by 2010. Power Sector 1.10 Total electricity generation capacity was almost 20,000 MW at the end of 1988, of which nuclear energy accounted for 33% and hydro, 11. Gross electricity generation during the year was 85.5 terawatt-hours (TWh), almost half of which originaLted from nuclear plants. Oil-fired thermal capacity amounts to 7,300 MK. Part of this capacity, however, has been shifted to gas-firing to absorb the cargoes of imported LNG which have been contracted for, pending development of more attractive markets for the gas (para 1.18). 1.11 Power demand is expected to grow rapidly in the future: the 1988 Power Development Plan (PDP) of the Korea Electric Power Corporation (KEPCO) envisages an average annual growth rate of 7.2% between 1989 and 2001. To meet the increase in load, KEPCO proposes to bring on stream about 15,700 MW of additional capacity over the next 12 years. The proposed mi, of plants features notably a number of coal-fired thermal plants (9,000 MW) and nuclear plants (5,600 MW). Doubts as to the feasibility of implementing this plan on schedule, however, have emerged rscently as KEPCO experiences increasing difficulties in siting new nuclear ..Ld coal plants because of strong environmental concerns voiced by local populations. In the case of coal plants, these concernis arise in spite of the fact that all new plants are to be equipped with scrubbers to control emissions of sulphur dioxide (SO2). In response to these difficulties, and to compensate for possible delays in its coal/nuclear program, KEPCO has been reviewing its investment program to include the phased construction of a (3,200 MW) gas-fired (combined-cycle) plant to be located at Incheon close to Seoul. Future Trends 1.12 The Korea Economics Energy Institute (KEEI) prepares regular updates of its projections of Korea's energy balance. The latest set of projections (Annex 1) forecasts an average annual growth rate for primary energy demand of 5.2% between 1988 and 2000. This is to be compared to an expected growth rate of GDP of 8X p.a., as the economy is expected to slacken because the manufacturing sector is reaching full capacity utilization. The implied energy/GDP elasticity of 0.65 is in line with wnat was achieved during the mid-1980s but may be somewhat optimistic as a long-term parameter in view of the sharp growth in energy demand erperienced during the last two years as the impact of previous energy conservation programs started to erode. Petroleum is expected to maintain its predominant position, accounting for 45-50% of total requirements. As indicated above, current power development plans anticipate a major role for imported bituminous coal, which would increase its share of Korea's energy balance to almost 30X by the year 2000. Within this general context, the potential contribution of imported LNG remains the subject of much debate. The latest projections prepared by the KEEI foresee an increase in LNG impoits from their present level of 2 million tons (2.6 million toe) to 6.3 million tons by 2000 and 10.4 million tons by 2010. These levels would be equivalent, respectively, to 6.01 and 7.5X of total primary energy demand in these two years. KEEI's projections are summarized in the following table: Table 1.1: Korea's Energy Balance (1988-2010) (in million toe) Average 1988 1995 2000 2010 Growth Rate p.a. (X) Petroleum 35.5 56.9 66.0 77.5 3.6 LNG 2.7 5.5 8.2 13.5 7.6 Coal 24.6 33.1 39.5 51.9 3.4 Hydro/Nuclear 10.9 15.5 21.8 31.5 4.9 Renewables 1.2 2.2 2.8 5.6 7.3 Total Primary Energy 74.9 113.2 138.3 180.0 4.1 Source: KEEI Government Policies in the Energy Sector 1.13 The main elements of the Government's present strategy in the energy sector, as they are reflected in the Sixth Development Plan (1986- 91), are to: (a) improve the institutional erficiency of the sector through the improvement of public enterprise performance; (b) gradually deregulate petroleum product prices and trade, and emphasize market forces in the establishment of economically efficient energy utilization patterns; (c) manage the growth in electricity demand through efficient pricing policies and load management techniques; (d) monitor investwent planning to ensure that capital expenditures are based on a least-cost development approach; and (e) promote cost-effective energy alternatives such as cogeneration schemes in the industrial and commercial sectors. Much progress has already been achieved towards these objectives. An area of concern is that energy prices have remained by-and-large regulated, with possibly deleterious implications on the efficiency of energy use as discussed further in this report. BL lbe Gma Iadusti 1.14 The Korean gas industry encompasses the import, regasification and domestic transportation and distribution to consumers (through city gas networks) of imported LNG; the production and distribution (also through pipeline reticulation) of manufactured gas in areas where LNG is (not yet; available; and the distribution of liquefied petroleum gas (LPG) in tanks or bottles. In many applications, pipeline gas and LPG are close albeit less than perfect substitutes. For households, both represent a greater degree of convenience compared to traditional fuels and their growing utilization over the years is a si&nifier of higher disposable incomes. Pipeline gas actually brings a higher degree of convenience compared to LPG and its use in urban areas reflects the high level of incomes achieved by part of the urban population. City Gas 1.15 The Korean city gas industry has a long, if geographically restricted, history, dating back to the construction of a gas plant in Seoul in 1935. Manufactured gas, produced through coal gasification, was available for home cooking until the plant was destroyed in 1950 during the Korean war. In 1972, the Seoul Metropolitan Government reinitiated a city gas service, providing naphtha-based manufactured gas and LPG-air mix as household fuels in support of government efforts to meet the growing shortage of charcoal briquettes and help mitigate the emerging air pollution problem in Seoul. 1.16 City gas distribution was subsequently expanded to other cities, starting with Pusan in 1982. There are now 19 city gas companies operating in Korea, seven of which are located in the Seoul metropolitan area. The number of hol'3eholds supplied with city gas increased from 164,000 in 1982 to 466,000 bj end-1986. With the introduction of LNG as city gas feedstock in the Seoul metropolitan area in 1987, the number of household consumers further increased to more than 500,000 in 1988. Because the introduction of LNG results in a reduction in gas cost, the pattern of city gas use where LNG is available is showing a gradual shift from its traditional role as a cooking fuel to become a possible energy source for residential and commercial space heating and selected industrial applications. Liquefied Petroleum Gas (LPG) 1.17 Domestic consumption of LPG remained limited until about 1979. Starting with the construction of the first domestic oil refinery in 1964, and throughout the 1970s, Korean refiners exported most of their LPG to Japan. From 1980. this situation started to change rapidly as the use of LPG as a cooking fuel began to grow, partly as a result of administrative measures. Consumption promptly exceeded the capacity of domestic refiners, resulting in large quantities of LPG having to be imported. A significant development has been the encouragement given to the use of LPG as an automotive fuel, which led virtuallF the whole taxi fleet to switch to LPG 6 - between 1980 and 1983. LPG consumpLion reached 2.2 million tons in 1988, of which 531 was for residential and commercial use (including city gas feedstock), 411 for transport, and the balance (6X) for small and medium- sized industries. Imports now account fot 581 of LPG consumption, most of which comes from Saudi Arabia. The KEEI energy projections forecast LPG use to grow at an average rate of 5.91 p.a. over the next two decades, reaching 6.4 million tons in 2010 (i.e., 561 of the expected LNG consumption on an energy equivalent basis). The competitiveness of LNG vis-a-vis LPG will condition the penetration of natural gas in a number of key markets. Based on present price forecasts, KEEI's market share projections appear reasonable, although they may underestimate the potential for LPG use in areas beyond the reach of gas infrastructure or at income levels which would not justify the costs of gas distribution. Natural Gas 1.18 In 1979, KEPCO initiated a study to establish the feasibility of importing LNG into Korea. A decision to negotiate with Indonesia for supplies was taken by the Government in 1981 and a contract between KEPCO and Pertamina was signed in 1983, covering imports of two million tons of LNG per annum for 20 years, starting in 1987 (with a potential additional one million tons starting in 1989/90). The objective pursued by the Government in initiating this venture was essentially threefold: (a) to diversify fuel supplies away from imported oil; (b) to address environmental concerns related to the use of charcoal briquettes for space heating in densely populated areas; and (c) to strengthen trading links with Indonesia. Use of natural gas was also seen as a means of improving the quality of service to consumers by providing a clean, convenient fuel at a competitive cost. Accordingly, the initial focus was on the eventual substitution of gas for char..oal and fuel oil in residential markets -- an objective, however, which could only be achieved over time through the progressive extension of distribution networks. To absorb the large quantities of gas required to trigger a gas import scheme, Korea had to resort to the expedient of burning gas in power stations originally designed for oil-firing. This has been done at a significant cost since LNG has been used to substitute lower cost HFO, although gas use in thermal plants has brought about significant environmental benefits. 1.19 When the decision to import natural gas was made in 1981, the Government initiated a policy of encouraging the development of city gas systems (in the Seoul area and in other cities). These systems were to operate initially on manufactured gas as a means of building up markets ahead of the inception of LNG deliveries. The strategy of the Government has been to license private distribution (city gas) companies to establish the needed reticulation. LNG supplies started in 1987. Gas utilization in 1988 was broken down into 1.9 million tons for power generation and 0.2 million tons for city gas. - 7 - 1.20 Institutional Arrangements. In 1983 the Government established the Korea Gas Corporation (KGC) as the agency responsible for the overall planning, operation and management of the infrastructure necessitated by the import of LNG, including in particular the receiving terminal at Pyeong Taek and the transmission pipelines required to serve the Seoul metropolitan area. KGC's main objective is to promote the use of LNG in accordance with government policies and to plan the gradual expansion of the gas system accordingly. KVC has established a research and training institute, in collaboration with Sofregas of France, for performing basic and applied research on gas technology and for training the necessary technical manpower. KGC falls under the jurisdiction of the Ministry of Energy and Resources (MOER), which directs policy making and oversees project implementation in the energy sector. 1.21 As already indicated, an interesting feature of the government strategy is that responsibility for the distribution of gas to the final consumers has been entrusted to private companies. To date, twenty one city gas companies have been licensed to distribute natural gas, seven of which have been converted to LNG. These companies are grouped under the umbrella of a City Gas Association (CGA), which acts as intermediary between the companies and the Government, KGC, local authorities and individual equipment manufacturers. CGA is responsible for coordinating the preparation of the annual three-yeat investment plans prepared by the companies at the request of the Government, and for data collection, publicizing the availability of LNG, ad hoc advice to customers, etc. More generally, CGA acts as the official spokesman for the city gas companies. 1.22 Another important agency in the gas sector is the Korea Gas Safety Corporation (KGSC), which is responsible for the preparation of all safety codes and regulations for gas distribution and utilization to be enacted by the Government. The scope of KGSC's activities is fairly broad, covering equipment and appliance testing, safety control research, and on- site inspection of gas plants, pipelines and customer equipment. Finally, the Korea Energy Management Corporation (KEMCO), which was established in 1980 to assist with government efforts at rationalizing energy utilization, is involved in a number of projects having a direct bearing on gas utilization, including cogeneration and district heating schemes. 1.23 Infrastructure. Construction of the LNG receiving terminal ac Asan Bay (Pyeong Taek), 60 km south of Seoul, and of the supply network to the metropolitan area was completed in 1986 at a total cost of about W 440 billion ($600-650 million at historical exchange rates). The terminal, which is built on a 420,000 sq m landsite, is equipped with four tank units of 100,000 cu m each capable of handling annually two million tons of LNG. Major facilities include piers, unloading, storage, boil-off gas treating, pumping, vaporizing and metering facilities and other auxiliaries. 1.24 After regasification, LNG is being supplied to the (4x350 MW) Pyong Taek power station located close to the terminal and, through the main transmission system, to the (2x250 MW) Incheon power station and the seven city gas companies licensed to operate in the Seoul metropolitan area 8 for residential, commercial and industrial use. The transmission system presently consists of a 98-km high-pressure pipeline linking Pyong Taek to Incheon and a medium-pressure, 128-km long circular network, branching off from the main line and connected to the city gas systems through seven governor stations. There are no interconnections among the seven city gas networks which have been developed independently of each other within their respective areas of jurisdiction. KGC's entire facilities are managed from a central control station in Pyeong Taek city which assures a safe and stable supply through remote control and monitoring devices. 1.25 In December 1984, KGC commissioned Daelim Engineering Co., Ltd., in collaboration with Sofregas, to undertake a feasibility study for a nationwide gas supply system. The study, which was completed in March 1986, recommended the construction of a national gas grid together with expansion of the Pyeong Taek terminal a-id, at a later stage, construction of a second terminal on the southern coast. The proposed investment program featured in particular the construction of a 500-kn trunkline across the peninsula to reach potential industrial base-load consumers in the south (Ulsan, Pusan) while tying in isolated city gas networks en route (Taejon, Daegu, etc.). The study envisaged increased imports of LNG (5 million tons p.a. by 2005) and a continuation of gas use in thermal power plants both to smooth out the seasonal fluctuations in non-power demand (essentially because of the winter peak of space heating needs) and absorb the step increases in gas supply that would result from new contracts. The study forecast the stabilization of LNG use in power plants in the early l990s at about 40-50X of total projected supply on the average. 1.26 To establish the financial justification for this investment, KCC commissioned KEEI to undertake a gas demand and feasibility study based on the original KGC technical study. The KEEI demand study was completed in April 1988. It forecasts that the use of natural gas would reach 2.3 million tons by 1996 and 4.7 million tons by 2006. Or, the basis of these projections, the study provided a positive endorsement of KGC's investment proposals. These proposed investments are still under review by the Government, mainly due to the large capital costs involved (W 530 billion or $800 million for the gas grid to the south only). A particular source of concern is the uncertain capability of the city gas companies to expand their networks and develop sales at a pace commensurate with the demand projections assumed in the feasibility study. 1.27 A major recent development is KEPCO's significant revision of their future needs for natural gas. This review has been prompted by a number of factors, including recent technological developments related to the use of gas for electricity generation, and growing environmental concerns over alternative options (nuclear and coal). These two factors combined have led to a significant reassessment of the role of the power sector as a gas consumer, which is now expected to shift from that of a swing consumer to that of a base-load consumer with its own economic and financial justification (which does not imply that gas-based generation capacity would necessarily be operated as baseload facilities in a power system sense). These developments are discussed further in the following chapters. - 9 . 1.28 Gas Distribution. Until 1987, the city gas industry consisted of independent gas systems fed by gas plants and supplying gas mostly to residential consumers, many of whom appear to be located in now development areas. The import of LNG and construction of a loop around the Seoul/Incheon area has made it possible to start supplying natural gas to the city gas systems located in the Seoul metropolitan area. This in turn has allowed them to deliver gas in much larger quantities, not only to residential but also to commercial and industrial consumers. On the demand side, the introduction of natural gas has lowered the cost to consumers and therefore expanded the potential market. For gas distribution, the main issue is therefore how to capture markets for which gas has a comparative advantage, at least cost. As discussed further in this report, the potential markets are large, although they are being continuously affected by rapid changes in the urban environment (e.g., large housing development programs, air pollution control measures affecting fuel choices). Capturing these markets, however, will require considerable expansion of city gas networks while maintaining the comperitiveness of gas vis-a-vis alternative fuels, at least in those areas where gas use is not protected by environmental regulations. As of the end of 1989, close to 1,900 km of distribution lines had been constructed in the Seoul metropolitan area. Government Objectives and Main Issues 1.29 The focus of government policy when LNG imports were first considered in the late 1970s was on the security of supply. Reflecting concerns that arose as a result of the oil embargo and the oil price shock, GOK's main objective was to effect the displacement of oil as the main source of energy through diversification of both the type and origin of energy supplies. LNG supply was, and still is, regarded as offering a reasonably guaranteed long-term energy supply source, isolated from possible political disruptions in the Middle East. However, to this foremost concern over security of supply, the element of energy quality has recently become an added motivation in considering LNG import on a large scale. 1.30 An important drawback to an energy strategy predicated in part on the import of LNG is that LNG trade is rather inflexible, with purchase commitments having to be made well ahead of time because of the long lead time needed for upstream investment in field development and liquefaction facilities. This places the onus on the Government (as the direct or indirect contracting party) to undertake a careful assessment of the potential demand for natural gas, and of the feasibility of the infrastructure required to meet the expected level of usage, before entering into import contracts which will be binding over a long period. Another critical characteristic of LNG trade is that it translates into a rather expensive gas price in end-use markets because of the high infrastructure costs involved, and therefore in a narrower window of opportunity than is the case in large gas markets supplied directly by pipeline. This issue is aggravated by the fact that Korea Ls an incipient - 10 - market for gas and large investments in local distribution networks are also required to bring the gas to consumers. 1.31 From these several angles, the import of LNG thus acquires strategic significance ir.asmuch as import would have to be effected on a sufficient scale to justify the necessary gas infrastructure by bringing down unit costs to a financially acceptable level. This will require a concerted decision on the part of the Government, in part motivated by environmental considerations, to make LNG a major fuel source. Should the Government decide to embark on an expanded LNG import strategy, it will need to develop an array of policies designed to bring about a sufficient level of usage and ensure that the available gas quantities are channelled to appropriate end-uses (taking into account the relative economic advantage of alternative fuels as well as their relative environmental impact) so as to fully justify the large investments required. These policies will need to cover pricing issues and, possibly, fuel allocation regulations. Also, as the Government is keenly aware, gas penetration in the economy will only be effective, or indeed feasible, if it is accompanied by a concomitant development of the end-use equipment manufacturing industry, both in terms of output and quality. Actually, suitable pricing policies, fuel use regulations and the encouragement of end-use technological development will have to be developed concurrently as self-supporting elements of an overall gas utilization strategy. Cost of Capital 1.32 An essential aspect of the gas sector (from import to consumption) is its high capital intensity. When comparing natural gas to alternative, less environmentally benign energy sources, which may be less expensive but would also involve far less capital investments by importers, transporters and consumers alike, the issue arises of an appropriate measure of the economic cost of capital in Korea. The official figure used by GOK, and the one used for the base case analysis in this report, is 13%. However, given Korea's large foreign exchange surplus and easy access to international capital markets, this figure may overestimate the actual cost of capital to the economy. As discussed further in this report, the impact of the cost of capital on the overall economics of LNG use may not be very large because gas use for electricity generation would entail considerable reductions in the capital requirements of the power sector, which would compensate for higher costs elsewhere. Yet, variation in the cost of capital is likely to affect the preferred pattern of gas consumption, as well as the potential contribution of each consumer category to common infrastructure requirements (which would have obvious pricing implications). Accordingly, we have tested the sensitivity of investment returns to a drop in the cost of capital to 8%, which appears as a reasonable lower bound (and actually is the figure used by KEPCO in its own planning exercises). D 11 - C. Environmental Issues Background 1.33 Energy use is one of the major sources of environmental pollution and, in Korea as in many other countries, the energy sector is increasingly influenced by environrental concerns. Due to its high population density and rapid industrialization and urbanization, environmentel concerns are actually probably greater in Korea than in many other countries. Choice of energy directly affects air quality, especially in urban and industrialized environments, and to a lesser extent, water quality and solid waste disposal; it can therefore be an important determinant in reducing pollution. 1.34 venerally, ambient concentrations of S02, total suspended particulates (TSP), non-methane hydrocarbons (HC) and, to a lesser extent, carbon monoxide (CO) and nitrogen oxides (NOx) give rise to air pollution. Major sources of air pollution in Korea consist of emissions from residential heating and cooking, industrial processes, electric power plants and automobiles. Air pollution in industrial areas arises from the high concentration of light and heavy manufacturing industries and processing industries, together with the increased generation of electricity required to support these industries. In general, residential areas adjacent to industrial comr±exes both in the Seoul metropolitan aree. and on the south and southeast coasts bear the full impact of the environmental consequences of industrial activity without the protection of desirable buffer zones. Unfavorable topographical conditions aggravate these impacts. 1.35 Another major cause of air pollution in densely populated areas is to be found in the combustion of fuels in stationary and mobile sources. In individual housings, b_Aquettes made of low-grade anthracite coal with a relatively high ash content are the predominant fuel for space heating. Domestic heating is estimated to account for about one third of total SO2 emissions and almost three fourths of the CO emissions in the country. The average height of the typical Korean house of 5-8 meters and the comparatively low level of flue gases which have limited buoyancy combine to produce high ground level concentrations of air pollutants. The problem is particularly acute in high-pcpulation density areas such as the several areas in Seoul and Pusan where density exceeds 50,000 residents per square kilometer, and is aggravated by the fact that coal in the traditional Korean home-heating system is burned at relatively low temperatures generating high CO emissions. Another source of SO2 emissions in urban areas is due to the common use of fuel oil for space heating in commercial and apartment buildings. 1.36 Overall, SO2 and TSP are the most serious air pollution sources in Korea. The average annual concentration of these pollutants in majcr cities as of 1987 is shown in the following table: - 12 - Cities Pollutants Units Standards Seoul Pusan Kwangju Daegu S02 ppm 0.05 0.056 I 0.039 | 0.014 I 0.055 TSP I mg/m3 150 175 197 105 146 i.37 Since the enactmi3nt in 1981 of regulations designed to decrease S02 concentrations, the annual mean S02 concentration in the city of Seoul Nas decreased to 0.056 ppm from 0.084 in 1978. However, S02 levels in Seoul, Pusan and Ulsan still exceed the prescribed annual air quality c'tandards. Moreover, daily standards are exceeded in many cities for a large number of days each year. S02 concentrations in major cities are seen to vary remarkably as a function of the season, increasing sharply with the winter heating season, but seem to remain relatively constant in purely industrial areas. This pattern again indicates that SO2 concentrations are strongly influenced by coal consumption for space heating in urban areas. A comparison with other industrialized countries .uggests that, with the exception of NOx, the level of air pollutants in Korea is quite h5gh. Further, continued urban and industrial growth will no doubt lead to greater pollution. With the rapidly growing vehicle fleet size and concentration, the levels of NOx will also increase. Governrnmt Reguaons 1.38 The Environment Conservation Law of 1977 as amended in 1986 provides the general framework for government actions in environmental protection. The law was enacted to broaden the scope of pollution control, and a number of special laws were introduced subsequently to deal with specific environmental issues, including the Air Pollution Control Law of 1980. The National Environmental Protection Institute (NEPI) was established as the entity responsible for the introduction and operation of a rountry-wide pollution control system. NEPI maintains a dense network of air and water quality monitoring stations: about two dozen automatic ;tations have been installed in five major cities capable of monitoring tive air pollutants, and a large number of semi-automatic stations are operating in other cities and in industrial complexes. 1.39 Ambient environmental quality criteria are provided in ministerial regulations framed under the Environment Conservation Law. Standards for SO2 were set in 1980 and for five other pollutants, namely, TSP, CO, HC, NOx, and oxidants (ozone), in 1983, as follows: - 13 - Classification Standards SO2 Annual Average : below 0.05 ppm 24 hour Average : below 0.15 ppm (should not be exceeded more than 3 .imes a year) CO Monthly Average : below 8 ppm 8 hour Average : below 20 ppm (should not be exceeded more than 3 times a year) NOY. Armual Average : below 0.05 ppm 1 hour Average * below 0.15 ppm (should not be exceeded more than 3 times a year) TSP Annual Average : below 150 mg/m3 24 hour Average : below 300 mg/m3 (should not be exceeded more than 3 times a year) Oxidants Annual Average : below 0.02 ppm (as 03) 1 hour Average : below 0.1 ppm (should not be exceeded more than 3 times a year) HC Annual Average : below 3 ppm 1 hour Average : below 10 ppm (should not be exceeded more than 3 times a year) Alternative Measures 1.40 The principal scope for improvements in urban air quality is through a reduction of emissions from the use of anthracite for residential heating, and to a lesser extent, from that of fuel oil for heating apartment and commercial complexes. Industrial pollution in adjacent areas also offers substantial potential for emission control. In the case of HFO, emission reductions can be achieved through reductions in the sulphur content of the fuel. Control of the characteristics of coal briquettes, however, is hardly feasible and the only feasible alternative in this case is to substitute a cleaner energy source such as diesel oil or natural gas. To date, measures for SO2 reduction have focussed on the use of HFO IJ and have included (a) the installation of desulfurization units at petroleum refineries; (b) the steady increase in imported supplies of oil with low 1/ In 1981, the maximum acceptable S-content of heavy fuel oil used in large urban areas was reduced from 4X to 1.6X. Moreover, KEPCO's power plants located in the Seoul metropolitan area have to use 0.3XS HFO. - 14 - sulfur content; (c) energy conservation including heat insulation; (d) introduction of central district heating systems as an alternative to central heating units for apartment buildings burning HFO; and (e) long- term contractual arrangements for natural gas import and its progressive use in residential, industrial and commercial markets. So far, however, gas use for space heating has been essentially restricted to commercial buildings (HFO users) and to a lesser extent high-income individual housings (diesel oil users), while largely missing the coal briquette market because of price. Regulations have been introduced that preclude the use of liquid fuels in some areas V, thereby providing a ready market for natural gas. Oil-fired power stations located in the metropolitan areas have also been instructed to convert their operations to gas, starting in 1991. Further tightening nf HFO characteristics is being considered by the Government.11 This ipproach, however, is going to be made increasingly difficult by the anticipated reduction in worldwide availability of sweet crudes. The trend towards heavier crudes, which is already apparent particularly in the Asia region, is going to lead to a deterioration in residual fuel oil quality, making it increasingly difficult to guarantee a large and continuous supply of quality fuel oil. 1.41 While use of coal briquettes is estimated to represent the main source of urban pollution in absolute terms, little progress has been achieved towards moderating its environmental impact. Facing difficult affordability issues, the Government looks at rising incomes as the only feasible solution to a seemingly intractable problem. However, the issue of the cost-effectiveness of the Government's approach to environmental control is open to question. In an earlier study, the Bank recommended that cost-effectiveness analysis of alternative environmental control strategies be undertaken before taking further steps to tighten emission standards. A good environmental data base was considered critical if such cost-effectiveness comparisons were to be meaningful and reliable. In this perspective, further improvements in the operation of the monitoring network and the quality of data were recommended, together with a closer involvement of the academic community in NEPI's monitoring effort. These earlier recommendations probably still stand today. The issue of cost effectiveness in establishing environmentel policies (including the prescribed use of gas under certain circumstances) is further discussed in this report. . Starting in September 1988, all large commercial buildings (i.e., with boiler capacity above 2 tons of steam per hour) located in specific areas were required to convert to LNG. This measure was first applied to the downtown area in Seoul and is progressively being broadened as gas availability expands. This measure, however, does not affect apartment buildings most of which continue to rely on (1.6XS) HFO for space heating. ./ Use of HFO in Tokyo is restricted to 0.2%S HFO. - 15 - D. Energ Price Outlook 1.42 Relative prices of alternative sources of energy are an obvious factor in assessing the merits of an LNG import strategy. GOK's earlier decision to enter into a long-term LNG import contract was probably motivated more by a perceived need to diversify sources of energy supply than by pricing considerations per se. Similarly, pricing factors may not be the foremost issue in future negotiations for additional import volumes as new considerations enter the picture, including trade balance considerations, the opportunity for Korean industry to participate in upstream gas development in the supplier's territory, and more generally the desire to strengthen specific bilateral relationships. Moreover, Japan has so far acted as the price setter in the Far Eastern LNG market and is likely to remain so to a large extent in view of the large additional import quantities under consideration by Japanese utilities. The extent to which Korea will be able to establish its own rationale in price negotiations therefore remains largely untested. This notwithstanding, price factors remain central to the establishment of a gas strategy for Korea, both as a determinant of the long-term demand for LNG and in the establishment of a rational (optimum) gas utilization strategy (to maximize the benefits of LNG use from a national standpoint). The LNG Market 1.43 Following years of relative stagnation, there are indications that the LNG market is poised for a period of renewed expansion. Two factors are seen as having a direct bearing on this change in market trends: first, increased uneasiness with nuclear energy and greater awareness of the onerous effects of oil ar.d coal burning and correspondingly of the advantages enjoyed by natural gas in this respect; and secondly, recent technical advance in gas technology for use in both the power sector and residential/commercial markets. Other relevant factors in the LNG industry itself include greater decentralization with a larger number of producers and consumers; and increased flexibility in the way LNG contracts are being structured. 1.44 The decline in the energy needs of industrialized countries during the 1984-86 period in the face of moderate economic activity and continuing conservation efforts had a dawpening effect on the LNG market which showed a relative stagnation during this period. Since 1987, however, energy demand has picked up as opportunities to reap additional energy savings through conservation become increasingly scarce partly due to lower oil prices. This has led to a surge in natural gas pipeline imports in Europe and in the United States and a re-emergence of LNG trading during the past 18-24 months. The bulk of the present and expected increase in natural gas demand is in the electric utility sector, spurred by the development of low capital cost combined-cycle units and the recent unprecedented growth of non-utility power generation, most of which is fueled by industrial gas-fired cogeneration units. The latter development - 16 - has been particularly true of the U.S. market which is characterized by relatively low-priced gas. The issue for Korea is to determine under what conditions similar trends can be expected to develop under generally higher price scenarios since gas has to be imported in the form of high-cost LNG. 1.45 Only about 13X of all marketed production of natural gas is traded internationally and LNG makes up 22X of this volume (or about 43 million tons in 1988). There are presently seven LNG exporters and seven importers. The LNG trade is dominated by the Far East, particularly Japan which currently consumes almost three-quarters of the world's LNG production, and Indonesia which heads the list of exporting countries with almost 40X of the trade. This concentration of LNG trade in the Asia region reflects in part geographical factors which preclude gas trade other than in the form of LNG, in sharp contrast with other international gas markets where pipeline tre.da is predominant. Japan is the region's biggest user of gas, with 1987 sales amounting to 12.3 bcm, equivalent to 4.4X of the country's total energy demand. Japan sees gas as a promising and secure long-term energy source, and it has played and will likely continue to play a leading role in LNG development. As more gas is being discovered I in the region, only a portion of which is exploited, prospects for a significant increase in traded quantities are good, with some projections actually forecasting a doubling in trade volume by the turn of the century, partly in response to a softening of contract terms (para. 1.47). The main LLNG consuming market would remain the Far East, with 73X of the cargoes destined to Japan, Taiwan and South Korea./ LNG Contract Terms 1.46 The inherent lumpiness of LNG technology has traditionally resulted in rigidly set trade arrangements. LNG flows have usually been organized in discrete, vertically integrated projects consisting of liquefaction plants, dedicated vessels for marine transport, ani storage/regasification facilities at the receiving terminal. Because of the large capital investments involved and the need for economies of scale, LNG contracts have traditionally featured largely inflexible (take-or-pay) delivery clauses (with no provision for resale) and rigid price formulas providing for linkage to official crude prices. LNG deliveries at high load factors were seen to be required to ensure the viability of long lead- time upstream investment. Such lack of flexibility, however, has proved a critical impediment to the development of the industry. LNG trade has recently shown signs of maturing: during the last two years, critical modifications were made to contract terms uvder existing contracts and even more drastic changes are being considered for new contracts. i/ Growth in LNG trade may actually be constrained by tanker capacity, which could clearly develop as an interesting export line for Korea (spearheaded by its own vessel needs, should it decide to expand LNG imports). - I/ - 1.47 The oil price slump during the mid-80s was indirectly responsible for bringing about basic changes in LNG pricing. Following contract renegotiations in 1988-1989, linkages in price formulas were shifted from official crude prices, which were often kept artificially high by producing countries (for taxation purposes), to realized export prices. While take-or-pay clauses in existing contracts have by and large been maintained, future contracts are likely to be more flexible and reflect more closely the competitive position of gas in the market place. New contracts forms are already emerging: arrangements for new Algerion sales to the U.S. are based on a netback formula related to the actual end-use market value of gas, and take-or-pay clauses are generally become far less stringent. One may expect this trend towards more flexible contract terms to continue, with prices eventually being set on a delivered basis and varying with market conditions. In this context, a (partial) indexation of LNG prices to coal prices may emerge in some cases as an attractive opLion.11 1.48 The oil price slump also sfiW the onset of spot trading. Spot sales were initiated by Indonesia toward the end of 1986, followed by Algeria and Libya. Spot trading was triggered by excess capacity both at liquefaction facilities and receiving terminals. Spot sales have so far been limited, partly owing to the improved flexibility of supply obligations in long-term contracts. Future contracts are expected to feature less constraining delivery provisions than the formerly binding take-or-pay terms although supplier'; will probably continue to expect some assurances from buyers of reasonable sales volumes. Moreover, an alternative to spot sales has emerged in the form of winter-peaking sales at a premium (e.g., in recent Algerian contracts with U.S. and U.K. utilities). In view of these developments, the market share to be assumed in the future by spot sales is unclear, and the extent to which they could be relied on for long-term supplies is probably limited. Price Outlook for Alternative Fuels 1.49 Import of LNG can be construed as a substitute for the use of a range of alternative fuels. These include a number of petroleum products (heavy fuel oil, diesel oil, kerosene, LPG), coal (imported and domestic) and, to a small extent, electricity. Most of these commodities are also imported by Korea, either directly (e.g., coal and LPG) or indirectly (e.g., domestically refined petroleum products). Expectations regarding future crude prices will affect a gas strategy inasmuch as (a) they will affect the overall demand for energy; and (b) they will affect petroleum product prices. They are not, however, as central to the overall set of issues as one might think since LNG contract terms have so far been and are likely to remain linked to a large extent to crude prices in one way or 2/ Several gas contracts already provide for a partial indexation to coal prices, including a recent Canadian pipeline export contract to the U.S. - 18 - another. Still, future crude prices will impact on the competitive position of LNG vis-a-vis coal, which is central to the issue of LNG use as a fuel for power generation. 1.50 The forecasts of crude oil and coal prices used in this study are close to the Bank forecasts. Moderate economic growth worldwide is expected to lead to a slight increase in oil demand, creating the conditions for a moderate price increase, although the possibility of sharp short-term disruptions (as shown in KEEI's own projections) is acknowledged. The proiections used in the study envisage a rise in crude prices from $18.5/bbl in April 1989 (Arabian light reference price) to $22/bbl in 1994 and $27/bbl in 2002 (in constant 1989 prices). Coal price projections are discussed in para. 1.54. 1.51 Petroleum product prices traditionally show considerable volatility because they are a function both of developments in the crude market and of future refinery invei4tments which in turn are a function of the industry's own price expectations, both regarding crude prices and product price differentials. For this reason, product prices, particularly the price of HFO, often follow cyclical patterns which make short-term predictions hardly relevant to a long-term energy strategy. The average price differentials between diesel oil, HFO and crude oil are the most relevant factors for our purpose since they condition the viability of secondary conversion investments in the refinery sector, and can serve as an indirect measure of benefits from the use of LNG as a substitute for oil products. The price of HFO is currently depressed because the maraet cannot absorb all the surplus fuel oil available in the market; over time this should be expected to trigger investments in refinery upgrading which may in turn reduce the price differential between diesel and HFO. Yet, strong demand for middle distillates in the Far East are expected to continue to exercise upward pressure on diesel prices. The price forecasts used in this study (Annex 2) reflect a fairly conservative view of future product price differentials: they show a slight increase over time in the diesel-HFO price differential (and a steady increase in the gasoline-HPO price differential). 1.52 LEG Plices. The major use of LPG worldwide is as a petrochemical feedstock, substituting for naphtha. As a result, LPG prices have historically tracked naphtha prices closely on a feedstock-equivalent basis (about 90Z of naphtha CIF prices on a weight basis). (Due to high transport costs, LPG prices (FOB) are far lower, and approximately in line with crude oil export prices.) LPG prices have recently been somewhat depressed mainly on account of the coming on stream of large additional capacity in the Middle East. While the additional exports are not really all that large compared to world LPG use, and can be substituted for naphtha in the petrochemical industry without major modifications, the outlook is for a continuation of surplus LPG production as the output of natural gas increases worldwide. A return to traditional price relationships between naphtha and LPG is therefore not expected over the period covered by this study, and our price projections incorporate the expectation of somewhat depressed LPG prices compared to historical trends. 19 1.53 The domestic prices of petroleum products are subject to import tariffs and similar levies, excise and consumption taxes, and price regulations at the refinery, wholesale and retail levels.PJ Due to these regulations, the structure of domestic product prices does not follow international price movements closely. As discussed further in the report, distortions in the petroleum price structure may impede the penetration of gas in otherwise economically attractive markets. The current schedule of posted prices is in Annex 3. 1.54 Coal Prices. Demand from power utilities in the Asia and Pacific region in 1987 was about 233 million tons. This is expected to increase to about 600 million tons by 2000 as most utilities in the region move towards increased use of coal. Of these quantities, about one quarter would be supplied by imports. The coal reserves of Australia and other coal-exporting countries seem to be sufficient to meet this increase in coal use. However, rapid increase in demand in the near term may create a tight market in the 1990s because of production and shipping constraints. The coal price projections used in the study (Annex 4) follow the Bank's forecast which envisages a growth rate of about 1% p.a. in real terms. These projections, however, may understate the relative price of coal to oil over the next ten years. LNG Price Projections 1.55 The Asian LNG market is poised for significant alterations over the next few years both in its volume and structure; however, the outlook for future prices and contract terms is still somewhat blurred at this stage. The most reliable prediction is that regional demand will go up significantly over the next 5-10 years, particularly due to the evolving attitude of Japanese power utilities. Total LNG exports to Pacific countries may reach 50-70 million tons by the end of the century as compared with 40 million tons in 1988. Yet, the market is also becoming far more competitive, with a number of potential suppliers considering the possibility of increasing their market share or entering the LNG business. For Korea, a non-exhaustive list of possible suppliers includes Indonesia, Malaysia, Brunei, Australia, the U.S. (Alaska) and Qatar. Generally, there is an expectation that the Asia basin will remain a buyer market for LNG for a number of years until the incremental impact of new contracts starts bearing on the availability of gas reserves in the region. The short- to medium-term outcome, however, is likely to entail some relaxation of cake- or-pay terms (in the form of an increase in the annual delivery swing on gas cargoes from 3% currently to possibly 10 or more). Price reductions are also a distinct possibility. Further negotiations to allow discounts from crude price parity could provide signs of future market directions. ii Ex-refinery prices are calculated on the basis of import prices, refining costs and a return on investment (10 after tax on equity capital). - 20 - 1.56 Long-term price trends are if anything more difficult to forecast although one can safely assume that future gas prices would be tied less mechanically to oil prices, with the price levels at which the regional Asia market will clear depending on the structure of gas demand as well as on supply conditions. Note that, because of transport costs, there has been so far little interference from the Europe/U.S. gas markets despite at times significant price differentials. This also could conceivably change, especially if spot sales acquire greater prominence. 1.57 An important factor is that the strengthening of the LNG trade will progressively lead to a commensurate tightening in the LNG shipping industry. The previous availability of laid-up vessels has already been essentially eliminated and a significant number of new vessels will have to be ordered to handle additional LNG volumes. In the case of Korea, any increase in LNG imports would call for additional shipping capacity as the two vessels employed under the existing contract already operate at full capacity. 1.58 For the purpose of this study, we bave developed a number of scenarios for the price of LNG under possible new contract(s), including a base-case scenario and three variants. LNG is presently priced on an FOB basis at about 90% of crude oil, which translates as a few percentage points above crude on a CIF basis because of transport cost differentials. Our base-case scenario is posited on the same general characteristics as the existing contract with the exception that transport costs are expected to be linked to fuel oil prices rather than adjusted by a constant annual factor. GOY has indicated that it might consider promoting the domestic manufacturing of LNG vessels, should additional contracts materialize. This, however, would not necessarily result in a reduction in shipping costs from their present levels ($0.65/mmbtu) which, if anything, might represent an underestimation of long-term costs. 1.59 To allow for the testing of investment recommendations under alternative LNG price conditions, we have also developed three variants that encapsulate possible developments in the LNG market: under the first variant, FOB prices are pegged at 85% of crude which translates at close to parity on a CIF basis; under the second variant, the ratios are 80% and 94%, respectively. Finally, a third variant reflects the possibility that future LNG prices could be pegged partly on crude and partly on coal prices (to better reflect its value in some important end-use sectors, particularly the power sector); under this variant, the base price is set at 90% of crude (FOB) and the index is based on a 50-50 average of crude and coal prices. Details of LNG price assumptions are shown in Annex 5 and summarized below. - 21 - Table 1.2: Energy Price Forecast a/ ($/GCal) Net Present 1991 1996 2001 2006 Value b/ LNG Scenario I 15.5 17.8 20.1 20.5 17.0 (base case) Scen.rio II 14.9 17.0 19.2 19.6 16.2 Scenario III 14.2 16.2 18.3 18.7 15.5 Scenario IV 14.9 16.6 18.3 18.5 15.6 Crude Oil 15.1 17.2 19.5 19.9 16.4 Heavy Fuel Oil 9.5 14.0 16.0 16.3 13.0 Diesel Oil 18.8 21.6 24.0 24.4 20.4 LPG (bulk) 16.3 19.1 20.8 21.1 17.1 Coal 7.8 8.4 9.1 9.1 8.3 a/ CIF prices in constant 1989 prices b/ 1989-2007 period at 13% discount rate 1.60 The following chapters provide (a) an economic assessment of gas utilization in the residential, commercial and industrial markets and in the power sector; (b) an assessment of possible long-term use of gas, based in part on a review of the dema.-.d projections prepared by KEEI; (c) an economic evaluation of the investments required to meet this potential demand; and (d) a brief discussion of the institutional issues involved in developing the gas industry in Korea together with a number of general recommendations. - 22 - 2. GAS UTILIZATION A. Introduction 2.1 Natural gas is a versatile fuel which can be used in a variety of applications by residential, commercial and industrial users. In the residential and commercial markets, gas is used mostly as a cooking fuel or for space heating (and cooling). In industry, it can be used as a boiler fuel, in direct heat processes, or as a chemical feedstock. Gas can also be used for electricity generation. The competitive position of natural gas vis-a-vis other fuels varies widely with the end-use process in which it is applied; it is also considerably affected by the social costs associated with the fuels' relative environmental impact. Because LNG costs are generally bigher than those of gas supplied by pipeline either from a domestic or an export source, the potential economic uses of gas in Korea, which is entirely dependent on LNG supplies, are more limited than in most other gas markets. Thus, use of gas as a chemical feedstock is currently excluded on the basis of current prices. 2.2 Although natural gas currently accounts for only a small part of Korea's energy balance, it is already being used in a wide range of end-use applications. Some of this use is based on the financial price of natural gas; in other cases, the added convenience or quality offered by gas is the most relevant factor from the customer's perspective. But in large measure, current gas use is often dictated by regulation or other government fiat. Thus, much of the gas use in downtown Seoul is dictated by government regulations related to air quality concerns. Also, much of the gas network construction to date has been made possible by the availability of subsidized government funding. Similarly, while KEPCO is presently the major consumer of LNG, this is mostly as a result of its 1ihavlng been instructed t pla;y the role of the "Cwing" consumer until gce can penetrate other end-use markets, so as to insure full use of contracted LNG quantities. Finally, again out of environmental concerns, all power plants in the metropolitan area initially designed for oil-firing would have to run on gas starting in 1991. Notwithstanding the rationale and merits of these government interventions in the process of gas allocation, a comparative analysis of gas utilization is in order to better underpin the rationale for government policies in the sector. End-Use Analysis 2.3 The purpose of this chapter is to delineate the scope for economic use of natural gas in Korea. This is done by way of a comparative end-use analysis designed to assess the economic (and financial) attractiveness of using natural gas as opposed to other fuels while, in a first step, ignoring differentials in environmental impacts. 23 - 2.4 The end-use analysis is intended to serve multiple objectives: (a) to help build economically consistent gas demand scenarios and estimate the economic value of natural gas in alternative end-uses for the purpose of economic evaluation of the required infrastructure investments (Chapter 3); (b) to provide a measure of costs involved in using gas rather than a cheaper but more polluting fuel in order to reduce environment-related social costs; and (c) to provide inferences regarding sector organization and policy changes required of private firms and goverment bodies to ensure market penetration in the most attractive end-uses (Chapter 4). In particular, cases where economic priorities are not supported by the comparative analysis in financial terms suggest needed changes in pricing policies or other regulatory mechanisms to alleviate distortions between economic and financial rankings. Methodology 2.5 The methodology used for the comparative end-use analysis is discussed in Annex 6 (together with details of the analysis). It is done on an annualized basis measured in terms of the ainnual energy requirements of each given type of consumer (GCal/year). The analysis is done both in financial and economic terms. The economic analysis is based on 20-year (discounted) averages of price forecasts, i.e. $17/GCal for LNG, $13/GCal for HFO, $20/GCal for diesel oil and $17/GCal for LPG (cif values in 1989 prices). The costs are built up from the point of energy production or import to the point of end-use.V This allows the calculation of the implicit Onetback value' of gas at that point in the system (i.e., the break-even price of gas that would equate the two cost streams from the 2/ Actually, for residential, commercial and industrial consumers, the point of comparison is set at the service connection. The costs associated with the service line, regulator and internal piping are therefore netted from the netback value of gas. This reflects the current marketing strategy of the city gas companies whereby consumers are required to finance their own service line ('Including meter and regulator) as well as all internal piping requirements. - 24 - consumer's perspective).PJ Further netting the actual import cost of gas from the netback value yields the consumer's potential contribution (available rent) to system investment, including basic infrastructure (terminal, trunk and city ring lines, and main grids) and distribution networks. 2.6 Korea is an incipient market for natural gas. The realization of residential, commercial and to a lesser extent industrial demand therefore hinges on the construction of new gas systems to serve these users. In that sense, Korea is at a disadvantage compared to mature markets where such systems already exist. Since gas prices are mainly determined by supply and demand in mature markets, the issue is whether gas prices would make the construction of high-cost gas systems attractive in an incipient market such as Korea. Since gas infrastructure is highly capital intensive, the answer to this question is largely a function of the cost of capital. The end-use analysis is predicated on a 13X economic cost of capital assumption. The extent to which a lower (8X) rate would affect the conclusions is discussed in para 2.40 2.7 In the case of the Seoul metropolitan area, the existing terminal and trunk line infrastructure can supply significantly greater quantities of household, commercial, and industrial consumption with cily an incremental distribution system and customer investment. In those cases, the existing terminal, trunk and city ring line should therefore be treated as sunk costs. In other areas, however, substantial additional investment in basic infrastructure will be required to make gas available and it is useful to estimate the potential contribution of each category of consumers to such investments. An attempt has been made to allocate the estimates of gas distribution costs by category of consumers in order to provide for a more meaningful comparison of the attractiveness of each end- use. This kind of allocation, however, suffers from methodological limitations and is also subject to much uncertainty; conclusions drawn therefrom should consequently be considered at best as indicative. End-Use Technology 2.8 Imptrtant inferences on institutional issues can be drawn from the comparative end-use analysis. The total economic cost of meeting any particular energy end-use is the sum of the economic cost of the energy commodity at the point of importation or production and the costs of taking the commodity to the point of energy consumption. Cost comparisons between natural gas and a competing fuel must also include the costs associated with the end-use technology (stove, boiler, etc.) with appropriate adjustments to reflect differing end-use efficiencies, if any. In many L/ In the case of residential consumers, the comparison is made on a 'new' selection basis (as opposed to the retrofit of existing appliances), reflecting the present policy of city gas companies to focus on supplying new housing developments. - 25 - cases, differentials in end-use costs and efficiency are found to be a critical part of the comparative calculus in determining whether gas is competitive. In the United States (and to a lesser extent in other large, well-developed natural gas markets) the end-use technology is very important to gas's competitive position. This is because gas end-use technology is often lower in cost and higher in efficiency than similar technology utilizing liquid fuels (and much lower in cost and higher in efficiency than the same technology for coal). In addition, in some cases, technology options are available for gas use but not for other fuels. 2.9 The issue of technology availability is therefore central to the whole question of gas-use economics although it is not easy to address. In Korea, the energy technology market, at least as it pertains to gas-firing equipment, in; not fully developed: some gas end-use technologies are not available; others are available, but at costs and efficiencies significantly less favorable to gas use than in other, more advanced gas markets. Finally, some technologies are not as readily available from as great a diversity of suppliers, or the technolrgies are not available in sizes to match large ranges of scale of end-use. The comparative end-use analysis allows an estimation of the importance of technology availability and inferences regarding changes needed (such the need to promote specific technologies) to facilitate penetration of the end-use market segments where gas would be most economic. The incidence of technological development on the success of a gas utilization strategy (both in terms of the pace of market penetration and the access to the most attractive market segments) is further discussed in Chapter 4. Coverage of Analysis 2.10 A series of representative end-use case analyses were constructed to examine the competitive position of gas from both the national (economic) and financial perspectives. The relevance of many consumer-specific factors (e.g.. end-use technology efficiency, unit consumption, etc.) calls for a sufficiently disaggregated analysis. In addition to the specific case of electric power, some 17 distinct case analyses were undertaken. These cases cover selected domestic, commercial, and industrial end-uses which differ in various ways and could therefore impact the comparative calculus. The results of this analysis are summarized below; further background data are in Annex 6. B. Residential, Commercial and Industrial Sectors 2.11 The strategy pursued by the Government has been to promote the development of city gas distribution networks so as to build up gas markets prior to LNG becoming available. Seventeen city gas companies have over the years been licensed to construct and operate gas networks. These networks were initially, and for those outside the Seoul metropolitan area still are, operated with manufactured gas (either from naphtha cracking or - 26 - LPG-air mix). LNG-based city gas thus needs to be compared to either one of these two forms of city gas, in addition to a range of fuels including kerosene, diesel oil (light fuel oil), LPG, HFO, and coal, as well as to electricity in some applications. 2.12 The general conclusion of the analysis is that LNG-based city gas is economically attractive based on narrowly defined economic criteria (i.e., without consideration of environmental factors) in selected household, commercial, and industrial end-uses where: (a) competition is against a high economic-cost fuel (at the burner tip). This category will likely always include LPG and city gas based on naptha and/or LPG; in some instances, light fuel oil (diesel) consumers also fit this category; or (b) user is willing to pay a premium based on the convenience or aualitv offered by the use of gas. Cooking falls in this category for most households; many industrial process applications also fall in this category; or (c) gas is used in combination with high efficiency end-use technologies which are readily available in other markets if not in Korea. Certain cogeneration and combined heating/cooling technologies fit this category. 2.13 The case-specific conclusions are summarized in Table 2.1. The results are sensitive to a number of parameters: in the case of large-scale consumers, relative fuel prices are the dominant element, while for the small-end of the market in terms of fuel consumptio.i (i.e., the residential and small-commercial markets) the magnitude of distribution and consumer costs becomes predominant. Hence, three factors are of direct relevance in characterizing the range of economic uses of natural gas: (a) the social premium attributed to gas because of its cleanliness; (b) the Korean gas utilities' past experience of relatively high construction costs (para. 3.34)W; and (c) the presently insufficient availability of gas-firing equipment in Korea, both in terms of volume and performance, compared to more mature gas markets. Policy decisions and correcting measures related to these areas will have a direct bearing on the magnitude and pattern of economically-justified gas use. i/ As discussed in paras 3.36-3.37, our estimates of future distribution costs, and even more so our allocation of distribution costs by category of consumers, is subject to much uncertainty (both because of methodological limitations and insufficiencies in the data base). The demand scenarios on which the consolidated economic analysis presented in Chapter 3 is predicated may therefore not be perfectly economically efficient in that they may conceal some implicit cross-subsidies among categories of gas users. - 27 - Table 2.1: S=mmary of End-Use Analysis ($/GCal) Netback Available Average Available Alternative Value Rent at Distribution Rent at End-Use Fuel of Gas Cons. Gate Costs City Gate a/ Residential Cooking Indiv. Houses LPG 49 b/ 32 105 (73) Apartments LPG 49i 32 29 3 Space Heating Indiv. Houses Diesel 53 c/ 36 13 23 Apartments HFO 22 5 6 (1) %ommercial Space Heating HFO 9-18 (8)-i 6-1 (13)-(0) Heating&Cooling HFO&elec 51 34 1 33 Hotels Sp. Heat. HFO 20 3 (0) 3 Htg&Cool. HFO&elec. 38 21 (0) 21 Restaurant Cooking LPG 44 27 15 12 Space Heating w/ Cogeneration HFO&elec. 27 10 2 8 Diesel 25 8 2 7 Industrial Boiler Fuel HFO 20 3 0-3 0-3 Direct Heat New Diesel 22-23 5-6 0-3 3-6 LPG 25-26 8-9 0-3 5-7 Retrofit Diesel 18-23 1-4 0-3 1-6 LPG 20-25 3-8 0-3 3-8 a/ Assuming an average price of gas of $17/GCal (CIF). b/ Based on lower-bound estimate of willingness-to-pay in city gas networks. c/ Assumes gas is used both for cooking and heating. 28 - (1) Residential Market 2.14 Residential consumption is often referred to as a premium market for natural gas. However, if the substituted fuels are generally of high value, and gas brings an undeniable element of convenience to the consumers, the unit investment costs are also high, with a large number of customers each consuming relatively small amounts of gas. Moreover, the space heating demand is highly seasonal, which aggravates the unit cost element. A close review is therefore needed in order to establish whether continued government intervention (through subsidized funding of reticulation investment or other means) is justified to promote the use of gas in this market segment. Domestic Cooking 2.15 In the absence of pipeline gas, LPG is the fuel of choice for domestic cooking. Compared to LPG, city gas (from LNG or manufactured gas) brings added convenience although at a significant added cost, and its penetration of urban markets over the last 5-10 years reflects the significant increase in domestic income achieved by the urban population. LPG is thus the fuel with which gas needs to be compared.1V The issue of quality and convenience is very important as cooking is a consumptive energy use, and therefore fuel preference, and hence 'willingness to pay' (and economic benefit), is strongly influenced by qualitative factors, particularly as household incomes rise. 2.16 While the introduction of LNG as a city gas feedstock results in a reduction in the cost of pipeline gas, city gas remains more costly, albeit more convenient, than LPG. The difference is very substantial for individual housing, less so in the case of apartment dwellings. The question is whether the consumer's preference is such that the additional costs are warranted economically ProfitAble city gas operations have established that single-dwelling consumers are willing to pay a price for convenience higher than LPG-equivalent. However, this (financially revealed) lower bound of the consumers' willingness-to-pay ($49/Gcal) is significantly lower than the estimate of economic costs of gas, including distribution ($122/GCal) (suggesting some cross-subsidy in the existing gas tariff structure). Absolutely clear-cut inferences as to the economic viability of gas use for cooking in individual housings are thus not possible based on the available data base. Although there is a possibility that gas distribution costs are somewhat overestimated, the issue is whether domestic consumers are willing to pay for quality the full extent l of economic costs of gas distribution. A detailed assessment of possible embedded subsidies (or cross subsidies) in the current tariffs would 1I/ Although coal-based domestic cooking remains prevalent among lower-income classes, it is not equivalent to a gas-based alternative on a quality and convenience basis and is therefore not considered. - 29 - therefore be required before the Government decides to promote LNG as a cooking fuel in individual housing units more aggressively, particularly since an acceptable alternative exists in the form of LPG. 2.17 In the more common case of individual apartment uni;s, an additional alternative would consist of LPG delivered in bulk to the apartment building and piped internally to individual apartments. This alternative would be equivalent in convenience and quality to direct access to city gas, while being probably cheaper both in economic and financial terms (despite unit costs of gas distribution for apartments being substantially lower than for single dwellings). If confirmed to be feasible, this alternative would undermine the rationale for city gas-based cooking by apartment dwellers (unless coupled with gas use fc.r space heating as argued below). We therefore recommend that the technical feasibility of this alternative be investigated. Space Heating 2.18 The choice of heating fuel by households varies both with the type of housing and income levels. The traditional Korean heating system operates with anthracite, which is heavily subsidized and partly for this reason remains widely used. Single family dwellings at higher income levels normally rely on modern boilers burning light oil (diesel). Apartment buildings which represent an increasing proportion of urban habitat, and indeed account for most new developments, meet their space heating needs by way of central heating facilities which usually operate on HFO. Individual heating systems in apartment buildings are rather rare (and are indeed barred for more than seven-storey buildings). District heating systems are now given increased attention in city planning. Two such systems are already in operation in Seoul and additional ones are at the planning stage. District heating, which is often considered in the context of (heat/power) cogeneration facilities, is discussed separately (paras 2.54-2.62). Since gas, contrary to other fuels, can be used both for cooking and space heating, the inter-fuel comparisons discussed in the following paragraphs assume that gas, if used for space heating, would also naturally be used for cooking. 2.19 Domestic Single Family. Comparing the use of gas (for cooking b and heating) with a combination of LPG for cooking and diesel for heating underscores its lack of (economic and financial) competitiveness in the individual housing market because of high unit costs of distribution, unless the convenience element in cooking is taken into account. On an incremental basis, however, gas use for heating is shown to be economically attractive if one assumes that gas would be used as a cooking fuel in any case. Moreover, if one applies the lower bound of the consumer's willingness-to-pay (as established by the ongoing gas tariff) as a measure of benefits derived from the use of gas for cooking, the combined utilization of gas for cooking and heating is only slightly less economically attractive than the gas/diesel alternative. On a financial basis, however, diesel remains substantially more attractive than gas (by - 30 - about 10), which points to the need for a more disaggregated gas tariff structure to better differentiate between cooking loads and the larger space heating loads which offer scope for substantial economies of scale in system designW. 2.20 Coal-based heating systems provide a distinctly lower standard of convenience than oil- or gas-based systems. Yet, a gas/coal comparison is also instructive since it is the Government's intent to reduce the incidence of anthracite burning in urban areas for environmental reasons. The comparison indicates, however, that the coal-based alternative, coupled with LPG cooking, is likely to remain prevalent in the absence of regulatory directives and/or special incentives to compensate for the high retrofit costs involved in a switch t' J cleaner fuel. For lack of reliable information on the economic cobt of domestic anthracite, the financial price was used in the economic analysis, which overestimates the attractiveness of anthracite use. Yet, even on this basis, anthracite is shown, for new systems, to bls less attractive (both economically and financially) than diesel oil and not significantly more attractive than gas. For existing consumers, however, the retrofit costs would be prohibitive and have in effect prevented a more massive shift from coal to diesel. For the same reason, coal users are less likely to be willing to pay the high costs of pipeline gas for cooking, which would have improved the case for gas substitution (for both cooking and space heating). The financial argument against fuel substitution away from coal is thus quite compelling and a coal substitution strategy motivated by environmental concerns will call for substantial government intervention (para. 2.76). 2.21 For apartment buildings, one needs to distinguish between central heating facilities (usually HFO-fired, but also possibly burning light oil or gas), individual heating systems (light oil or gas) and district heating. The planning practice of city gas companies is to assume the availability of gas for cooking. As mentioned in para 2.17, the possible alternative of piped LPG needs to be investigated. Also, consideration of the individual versus central heating options is important for multiple reasons: as incomes rise, households will increasingly want the control and convenience of regulating their own space heating, while, at lover incomes, a family may not want the burden of common heating standards if these are higher than their own. Examination of the individual versus central system also allows consideration of important institutional issues related to first costs, including whc bears the cost, available financing, etc., all of which can be expected to impact directly on fuel and technology choices. 2.22 A comparison of options available, including the central and individual gas alte.:natives, a diesel (light fuel oil) individual option and a central heating Bunker-C (HFO) option shows the Bunker-C option to be least-cost both economically and financially for new buildings. However, 11/ Unit consumptions are in a ratio of about 1:7 on an average basis; taking the seasonal variations in heating loads and the daily variations in cooking loads into account, the relevant ratio is probably about 1:3. - 31 - in economic terms, the individual gas option is hardly distinguishable (and actually becomes the most competitive option when using a lower discount rate of 8x). This suggests that, for new construction, individual gas heating may be attractive, particularly since the individual convenience element would increase its attractiveness to the consumer. Distortions between financial and economic prices, however, will be a barrier to such use: in financial terms, Bunker-C for central heating is much cheaper than gas. Although an individual gas option will be hindered by the question of first cost financing, as well as by government regulations preventing individual heating facilities in buildings of more than seven stories, we recommend that this approach be considered as a possible component of a cost-effective pollution abatement strategy. 2.23 Gas use in central heating facilities would only become feasible if the Government decides to further tighten existing regulations on HFO use in urban areas. The comparison shows the eccnomic premium between HFO and gas for a typical (600 units) apartment building to be equivalent to about S4/GCal of HFO (or $42/ton) IV; this is significantly less than the diesel/HFO differential but higher that the premium currently applicable to low-sulfur fuel oil on international markets, which would therefore seem to be the most logical first step to improve the environmental impact of apartment heating loads. In the absence of specific government regulations, it would appear that gas may be in a better position to penetrate the apartment heating market through its use in district heating schemes (paras 2.54-2.62) than as a central heating fuel. (2) Commercial Market Space Heating 2.24 The intensity of energy use, which impacts on the scale of gas installations, is the most critical factor when analyzing the scope for gas utilization for commerciRl spAee beating where HFC 's the fuel normally used. Two bounding cases were considered to characterize this relationship.lM The case of combined heating/cooling facilities was considered separately, as well as that of hotels (because of their greater energy needs per unit of space). 2.25 Alternative fuel options include diesel-, Bunker-C- and LPG-based boiler systems. For small-scale commercial consumers, LNG city gas is clearly not competitive with Bunker-C fuel oil, either in financial or in economic terms, despite a significant difference in boiler 12/ On a marginal basis (i.e., ignoring any contribution toward the cost of basic gas infrastructure but including gas distribution costs). 13/ The range of floor space considered goes from 3,300 sq m (1,000 pyong), which represents the lower end of commercial buildings served by Kukdong City Gas Co. in downtown Seoul, up to 39,600 sq m (12,000 pyong). - 32 efficiency. This is because, for smaller commercial buildings, gas-related distribution and customer (boiler, service connection, piping) costs account for most of the expenditures. However, the impact of these distribution and customer costs is dramatically lessened at larger scale and higher annual gas uses. Thus, for commercial consumers with floor space of about 40,000 sq m, Bunker-C and gas are almost equivalent although Bunker-C remains much cheaper in financial terms. This suggests that at larger scales, natural gas may be an economic alternative for commercial space heating, although such a choice will not be made based on current financial prices. 2.26 Government regulations now preclude the use of liquid fuels in - commercial buildings in downtown Seoul. Given the environmental benefit of using gas, this policy appears appropriate for large buildings. However, for smaller buildings, additional examination would be useful to determine whether such fuel-switching, environmental regulations are grounded on appropriete economic rankings, taking into account in particular that at the low end of the market, (low sulfur) diesel would appear to be more economical than gas while offering a reasonable environmental impact. 2.27 In the case of hotels, which exhibit a much higher (per unit of space) energy use, Bunker-C is again the least-cost option in financial terms, but in economic terms LNG gas is now lower in cost. This reinforces the conclusion that at larger scale and/or higher usage where the impact of infrastructure anw customer costs are lessened, natural gas may be an economic alternative for commercial space heating. But again, such choice will not be made based on current financial prices. Restaurant Cooking 2.28 Comparative analysis also shows gas to be quite attractiv'e in the restaurant cooking market. This is due to the fact that competition in this market segment is essentially against fuels which also start out with high energy commodity (as opposed to delivery and end-use technology) costs, in particular LPG. The attractiveness of gas use increases with the size of the restaurant as the weight of the capital cost components (in total costs) decreases with the level of usage. High End-Use Efficiency Options 2.29 The commercial market offers the potential for a number of end- use options which achieve high end-use efficiency by meeting jointly two energy end-uses, thereby considerably enhancing the attractiveness of gas utilization from both economic and financial standpoints. These options are based on technologies not yet widely marketed in Korea although they should be central to an effective gas utilization strategy. 2.30 Combined Heatina and Cooling Systems. These systems, which are based on gas-fired absorption technology, would make gas quite competitive 33 in economic terms (compared to the HFO/electricity alternative). Moreover, increased gas use in summer to fuel air-conditioning systems would help improve system load factors. Financial pricing, however, could be a market barrier that may impede gas penetration of this attractive market segment. 2.31 Cogeneration of Elec Xicity and Steam. Commercial offices can also make use of internal combustion engine technology for the joint production of electricity and heat.1W A review of such cogeneration options is complicated by the range of technical alternatives available which vary in their mix of electricity, steam, and heat outputs and can be used to meet a wide variety of end-uses: lighting, shaft power, space heat, process heat, space cooling and dehumidif£zation. Furthermore, the operating procedures can vary from thermal to power load following and can involve power sales to the grid or only in-house use. 2.32 The economics of cogeneration are sensitive to the transfer price of electricity which accounts for more than one-half of total costs. Valuing electricity at $0.10/kwh, gas-based cogeneration schemes is shown to be economically attractive for a wide range of sizes.U/ Thus, in comparison to a boiler-only option (i.e., for steam only), the marginal cost of cogenerated electricity in a typical (gas-fired) commercial unit is estimated at about $0.07/kWh. Cogeneration technology (both for commercial and industrial applications) holds much potential for cost-effective gas use and its availability needs to be promoted, particularly among lower- scale users. (3) Industrial Sector 2.33 The potential use of gas in the industrial sector falls under three major headings: process heating (e.g., in furnaces, kilns, dryers, etc.), steam generation (i.e., in boilers and cogenerators) and feedstock use. Interfuel competition between natural gas, oil and coal in the boiler market is largely determined by fuel prices, including handling and storage I4/ Cogeneration is a technology whereby electricity and heat a-e produced together, the heat being used to heat and cool buildings (ty means of absorption chillers) or in some other (industrial) processes requiring heat. The advantage of cogeneration is that, under certain conditions, joint production of heat and electricity offers economies of scope compared with the generation of electricity in a central station and the production of heat in a separate boiler. Gas-fired cogeneration systems have become quite common in well-developed gas markets such as the U.S. Such systems can also be operated with distillate oil; the other alternative for the purpose of economic evaluation is that of producing heat in a separate boiler (gas or fuel oil-fired) with electricity purchased from the grid. DJ However, diesel cogeneration would be the least-cost option on the basis of financial prices. costs, and environmental regulations. In contrast, the relative merits of each fuel for process heating vary .-tth each specific application. 2.34 The main advantage of natural gas in industrial applications lies with its ease of use and, in some cases, in its quality as a fuel. Additional benefits result from lower operation and maintenance costs of energy equipment (particularly compared to coal), and from the fact that gas-firing eliminates the need to carry fuel inventories. Despite these advantages, there are limited prospects for the use of gas as an underboiler fuel, except for environmental reasons in densely populated areas; gas should then be targeted to those industrial applications calling for higher operating temperatures which cause greater emissions of nitrogen oxides. The poor competitiveness of gas in the boiler market is partly due to the fact that domestic gat boilers have not yet reached the efficiency standards achieved in more Pdvanced gas markets. However, gas can compete effectively where its quaitty or some other characteristic is relevant to its end-use, such as in a number of direct heat and drying processes where gas enjoys a clear, albeit difficult to quantify (generically), technical advantage (because of its clean combustion and better flame quality due to its paucity of impurities, easy heat control, and other factors). 2.35 Industrial utilszation is characterized by high unit consumption. Five separate cases of direct heat applications were examined to allow for a sufficient range of assumptions for gas utilization and conversion (retrofit) costs, covering the glass industry, metal industry, food processing industry, textiles industry, and electronics industry. In all cases, the assumed substitution is either LPG or diesel or some mixture of the two fuels. To reflect the salvage value of equipment in place, a lOX salvage value (retrofit) case and a lOOX value (new/whole replacement) case are used for bounding characterizations of the conversion costs involved. In all cases, gas is shown to be the fuel of choice although distortions in the financial rankings indicate that pricing could be a severe barrier to gas penetration in the sector. This points to a substantial potential for economic use of gas in the industrial market. However, gas will be able to make large forays in the industrial fuel market, and thereby achieve significant economic gains, only if supported by an intensive R&D effort in gas technology development. 2.36 The chemical feedstock segment of the industrial gas market does not appear to hold much potential in Korea, at least based on present prices. At this point, international prices of ammonia and other methane- based chemicals (e.g., methanol), which are driven by low-cost producers elsewhere, would not justify LNG-based production in Korea. In that sense, the situation of Korea is ratbar different from that of most other gas markets where, under certain conditions, use of (methane) gas as a chemical feedstock may be justified. 35 (4) Conclusions 2.37 The above comparative end-use analysis suggests that gas competes effectively with other fuels (both economically and financially) only in selected end-uses. These include special high-efficiency technologies, and cases where its quality or other characteristics allow it to compete with all fuels, including those with low commodity costs such as Bunker-C, on a non-price basis. In the residential market, gas will continue to penetrate the cooking market because of the added convenience it brings to consumers compared to bottled LPG. Except as dictated by environmental and other regulations, retrofit customers are largely ruled out (with the possible exception of LPG for cooking or other use where the convenience element would be predominant). As shown in Table 2.1, the capacity of each category of consumers to generate sufficient surplus from fuel-switching to cover part of the cost of the main gas infrastructure (over and above their estimated share of distribution costs) varies widely. Moreover, there are frequent distortions between economic and financial rents. The analysis thererore suggests the need for a more selective approach by the Government in supporting reticulation investment by the city gas companies through subsidized funding (from the Oil Fund). Efforts should be made to target financial incentives to priority market segments in lieu of the present, largely indiscriminate approach. The alternative of providing a greater proportion of government support directly to the consumers also needs to oe investigated. This would allow Government to focus its intervention on those categories of consumers for which the environmental factor is most relevant but where fuel switching is seen to require special incentives. 2.38 City-gas operations have so far concentrated on the cooking, water heating and part of the space heating markets. The analysis indicates that part of the commercial and industrial energy markets also offer attractive opportunities for LNG use (particularly if one takes environmental factors into account as discussed in paras 37-38). Experience elsewhere has shown that fuel demand by industries is usually characterized by a high price elasticity. In Korea, however, the low price of fuel oil in relation to other fuels, as established by the Government, has so far largely precluded gas penetration of the medium- to large-sized boiler fuel market. It is also apparent that switching from HFO boilers to a more sophisticated and efficient use of energy in (gas-fired) cogenerators or advanced heating/cooling systems in large buildings would also be hampered by the low price e. fuel oil. Conversion of HFO users to gas has so far occurred mainly on account of fuel use regulations motivated by environmental concerns. Alternative approaches combining price adjustments (to better reflect true economic values) and financial assistance to consumers (for equipment financing) need to be developed. Such combinations of incentives and disincentives should be set both on an end-use basis and a regional basis. 2.39 Our base case scenario assumes that LNG (under the existing as well as future contracts) would continue to be priced close to crude oil parity on a CIF basis. On this basis, the competitiveness of natural gas 36 in the large commercial/industrial boiler market would be justified only when connections to the grid would involve small additional costs. A reduction in the price of LNG of say 10 would not significantly affect the overall pattern of gas use, but it would ease the case for gas utilization in the boiler market where interfuel competition is the most severe. The impact of LNG price reductions on the economics of infrastructure investments is discussed in Chapter 3. 2.40 The end-use analysis was tested to a lower estimate of the cost of capital (8X). Results are summarized in Annex 7. As for the impact of the price of LNG, a lower cost of capital would not affect the overall pattern of gas use (as justified economically). It would, however, improve the economics of gas use, particularly for cases where either the costs of gas distribution or those of end-use equipment are significant. Thus, a reduction of capital charges would considerably strengthen the economic prospects of residential distribution, although the netback value of gas (as derived from the consumers' willingness-to-pay revealed by the current tariff) would still remain insufficient to cover the full costs of distribution. Cogeneration projects would also see much improved returns. 2.41 Need for Additional Case Coverage. While attempts were made to include a reasonable coverage of potential users to provide the foundations for a general assessment of the economics of gas imports, additional cases will be needed to further structure the government strategy in the sector. Examples of additional needed cases are ones examining low-cost high- efficiency end-uses such as space conditioning with cogeneration and/or gas-fired absorption systems, using technology not yet, or only recently becoming, available in Korea, and the many industrial process applications that benefit from the quality or other characteristics of gas use. 2.42 Costs and Efficiencies of End-Use Technologv. Our case study analysis is based largely on costs and efficiencies of end-use technology as is presently available in Korea. However, equipment and appliances available domestically often do not provide the comparative advantages enjoyed by gas-using technologies in well-developed gas markets such as the U.S. Cost reductions (either capital or non-fuel operating costs) or efficiency improvements would affect the competitive position of gas in a major way. Access to the proper technology would also help redress possible market barriers due to fuel price distortions. To our knowledge, no survey of technology availability in Korea has been made to date and this should be an important item in the development of a gas utilization strategy. A review of gas technology available in the United States was carried out by consultants commissioned by the Bank in preparation for this study;z1 the results of this review could provide the starting point for an assessment of technology availability in Korea. We recommend that such a survey be carried out, leading to a plan of action for the development of appropriate technologies and encouragement of their broader availability in the market place. 16/ 'Korea Gas Sector - Review of End-Use Technology,' deLucia and Associates, 1988. - 37 - C. Gas Utilization for Electric Power Generation Introduction 2.43 There is keen interest worldwide in natural gas as a fuel for power generation. Recent projections by the American Gas Association anticipate that increased gas consumption by power utilities will account for most of the growth in overall U.S. gas demand, increasing from 80 bcm in 1988 to 175 bcm by 2010 (i.e., a 3.6Z p.a. growth rate). Japan has actually pioneered the large-scale use of gas for power generation, allocating most of its LNG imports to this end (as much as 831 in 1987), and the growing needs of its power utilities are behind much of the large increase in Japan's LNG demand anticipated over the next ten years. Similarly, the U.K. is now allocating a large share of its gas to private power projects. A number of factors have caused this keen interest in gas- based generation, in particular continued growth in disca,vered gas reserves which are now perceived as sufficient to support large-scale power developmentiLJ; the cleanliness of gas as a fuel; the debate surrounding nuclear energy; and recent technological advance which has led to critical improvements in the design and performance of combined-cycle power plants, particularly (although not exclusively) when fired with natural gas. These factors are of particular relevance to Korea's current energy outlook and will have a direct bearing on its potential use of LNG over the next 10 to 20 years. 2.44 The alternative technological options available to KEPCO for future power system expansions include nuclear plants, coal-fired and oil- fired conventional steam power plants, and combined-cycle plants which are normally gas-fired but can also be operated on distillate oil (and are also now integrated in recent coal gasification processes; para 2.71). Gas- fired combined-cycle plants have for some time been considered as an attractive option to meet peak and intermediate loads because of their low capital costs, short construction period and high efficiency. Further efficiency improvements in gas turbine technology have significantly enhanced their attractiveness as base-load facilities. In particular, their reliability and availability ratios have increased markedly and they are now routinely and reliably used in baseload cycles.121 A combination of factors somewhat specific to Korea has further enhanced the potential contribution of gas-fired combined-cycle plants towards meeting part of Korea's future electricity needs, including (a) the increasing difficulties experienced by KEPCO in identifying suitable coastal sites for new nuclear 1/ In the past decade alone, proven gas reserves in the Asia/Pacific region have doubled to nearly 235 trillion cubic feet (tcf) in 1988, i.e., about a third more than oil reserves. At current rates of production, known gas reserves would last 60 years, compared to 12 years for oil. 1]/ Firing temperatures in excess of 12500C are now achievable with good expected availability (over 90S). - 38 - and coal-fired plants (while combined cycle plants can be installed inland or at sites otherwise unsuitable for nuclear or coal-fired units, in particular close to urban centers); (b) the public's increased uneasiness vis-a-vis further nuclear expansion; and (c) stricter guidelines for air pollutant emissions, water discharge and solid waste disposal. 2.45 Clearly, environmental considerations explain much of the current interest in gas-fired combined cycle technology throughout the world. Combined-cycle plants also benefit from low c'spltal costs and relatively short engineering/construction periods, and offer modular design features that allow utilities to add generating capability in small increments with short lead-times, minimize concentration of financial capital and better respond to uncertainties in power demand outlook. Also, gas firing minimizes fuel preparation and handling problems. One would expect that similar considerations would apply to Korea at a time when an extensive expansion of the power system is being considered in response to the anticipated growth in power demand. Economic Comparison of Alternative Generating Options 2.46 The correct method to select a least-cost expansion path for electric systems is through an optimization of system development to serve forecasted loads with given reliability criteria. Such an exhaustive system analysis, based on WASP or other system simulation methods, falls beyond the scope of this study although it would clearly represent a logical follow-up. KEPCO is using WASP simulations on a routine basis to optimize its power development program. It would be useful to update these analyses based on recent data on combined-cycle efficiency and reliability performance, as well as with broader assumptions as to the possible future availability of natural gas (i.e., outside the Seoul metropolitan area) so as to facilitate the planning of gas infrastructure. 2.47 A common simplified approach to the evaluation of alternative generating units consists in the calculation and comparison of unit generating costs (busbar energy costs), i.e., annual capacity charges (including O&M) and fuel charges at a given load factor, divided by the annual kWh generated during the year.WL The capital costs can be adjusted to capture three issues: (a) construction times and the corresponding opportunity cost of capital; (b) effective capacity differences due to unplanned outage rates; and (c) differences in accompanying transmission costs. This simplified analysis is sufficient to establish the need for serious consideration of combined-cycle plants in future sector planning efforts. Details of the calculations are in Annex 8. 12/ As for the end-use analysis of other gas markets, the approach is again one of average or levelized cost analysis. Comparisons are made on the basis of the average projected price of alternative fuels over a 20- year horizon. - 39 - 2.48 As for previous end-use analysis, the netback value of zas is a measure of potential economic benefits to be derived from the use of gas in a given application.3EM This netback analysis estimates the breakeven cost of gas delivered at a combined-cycle power plant gate vis-a-vis other fuels and generation technologies. The netback value is thus a function of the alternative technology against which combined-cycle plants are being measured. Because capital cost differentials are such an important factor in the comparison, the estimated netback values are also highly dependent on the assumed load factor of the plant and the cost of capital. 2.49 Capital Costs. It is difficult to make precise estimates of the capital cost of alternative generation options because of the preponderance of local factors. Thus, the capital costs of coal units depend to a large extent on the environmental regulatory framework in which they operate. While nuclear plants are also clearly affected by environmental controls, their unit costs largely reflect the degree of equipment standardization achieved by the utility. One also needs to differentiate between new site development and capacity additions at existing sites where one would exjpect economies of scale in the use of offsites. The mission endeavored to develop a consistent set of cost estimates (for new site development) based on worldwide experience but integrating as much as possible past construction experience in Korea. The basic assumptions, which arc summarized in Table 2.2, refer to 1989 prices and are considered typical.W, 2.50 Efficiency. Availability and Reliability. The net efficiency of the latest gas-fired combined cycle plants is around 48X (based on low heat value [LHV]); further efficiency gains (of about 5 percentage points) widely expected to be achieved over the next ten years through continual optimization of gas turbine designs are ignored in the analysis. In comparison, the efficiency of conventional (steam turbine) plants is estimated at about 38X for coal-fired plants and 39Z for oil-fired 201 Note that netback values could be quite different if calculated in the context of a WASP-type model. j1/ Combined cycle plant costs should be corrected to reflect the savings in transmission costs due to the fact that they can be located close to the main load centers; annual savings in transmission expenditures were estimated by KEPCO to range up to US$15/kW/yr for a Seoul plant that would substitute for a coal plant located on the southern coast. Combined _ cycle plants that would be located in cities in the southern part of the country (assuming gas availability) would generate somewhat smaller savings. - 40 - plants.W Combined-cycle and conventional steam technologies also differ significantly in their availability (probability of planned and unplanned outage) and reliability (probability of unplanned outage), especially when natural gas and coal are compared. While in the past the performance of combined cycles was limited because of problems associated with gas turbines, the latest combined-cycle plants which incorporate recent technological advances are reported to operate with availabilities of over 902, compared to about 70X for conventional coal units.WV Dependin.g on such system characteristics as demand seasonality and the ratio of individual plant size to system size, the difference in scheduled maintenance periods may or may not lead to major system cost differences. At any rate, however, the difference in outage rates will ca&l for additional reserve requirements for steam coal facilities ir. order to provide the same quality of service. Table 2.2: Plant Cost and Performance Data Plant Cost Heat Rate Efficiency Availability O&M c/ (S/kWM a! (Btu/kWh) (X) (X) b/ (Sc/kWh) Convent. Steam Coal 1,100 d/ 8,980 38 70 1.15 Oil 900 8,750 39 80 0.65 Combined-Cycles Gas 650 7,200 47 93 0.36 Light Oil 650 7,600 45 85 0.40 a/ overnight costs. b/ 100l less probability of planned and unplanned outage. c/ at 65X load factor. d/ including flue gas scrubbers. D2/ While the efficiency of a combined cycle plant drops under partial load operating conditions, it always remains above that of conventional plants with similar rating. Moreover, in the case of multi-turbine combined-cycle plants, broad use of the high efficiency of individual gas turbines under full load conditions can be made when operating the overall plant under partial load conditions by isolating one or more gas turbines and operating the remaining ones close to full load conditions. Also, a combined-cycle plant equipped with a fully fired boiler would be able to maintain its highest efficiency even under partial load conditions. In general, therefore, combined-cycle plants compare very favorably with most other generating alternatives in their ability to follow the utility load curve easily, i.e. to operate under changing load factor conditions with fairly consistent efficiency. D/ For a unit in the 450 MW range, the implied cost differential is estimated at about $45m (or $100/kW of installed capacity). - 41 - Netback Value of Gas 2.51 Our base case comparative analysis underscores the economic attractiveness of gas-fired combined-cycle plants when compared with (new) coal-fired stations. Based on an assumed (discounted) average price of delivered coal (including harbour and handling charges) of $55/ton ($8.8/GCal), the base case netback value of gas is $27/GCal (at 66.51 and 58.21 load factor for gas and coal plants, respectivelyW). Differences in efficiency, capital costs and OM costs between the two technologies can be translated as premiums to gas (compared to coal) on a calorific unit basis ($/GCal), as shown in Table 2.3. Note that combined-cycle plants using distillate oil would also be an attractive alternative to coal-fired stations albeit significantly less so than gas-fired plants; yet, this indicates that diesel oil could provide a convenient backup in the case of gas supply interruption.W Use of gas is also shown to be attractive in peaking combustion turbines. Table 2.3: Gas-Coal Value Differentials ($/GCal) Cost of Canital 13X 8X Average Discounted Coal Price 8.8 8.9 Fuel Efficiency Differential 2.2 2.2 O&M Cost Differential 4.4 4.4 Capital Cost Differential a/ b/ 11.5 6.6 Netback Value of Gas 26.9 22.1 a/ at 66.5X load factor for combined-cycle plants and 58.2X for coal-fired plants to reflect differential in availability. b/ ignoring differential in transmission requirements. _/ The differential in load factors is used as a proxy to account for the difference in availability between the two technologies. Alternatively, the capital costs for the coal alternative could be marked up to reflect the additional capacity reserve requirements necessary to provide a similar level of reliability as the gas alternative. 2/ If one assumes that in actual operating conditions, the alternative to a combined-cycle plant capable of load following performance would be a mix of coal steam turbine operating as base-load capacity and distillate combustion turbine as peaking unit, the netback value of gas would be about $2/GCal higher than in the base case. - 42 - 2.52 While the analysis underscores the potentially large economic benefits to be realized from the use of gas in generating electricity, the estimated economic rent (i.e., the difference between the netback value of gas and its economic cost) (a) will be a function of plant location and (b) is sensitive to the assumptions made in regards to key parameters. In particular, actual demand for gas can only be determined through a power system optimization program that incorporates, inter alia, estimates of the cost of gas at various locations (para. 3.12). While direct comparison of the netback value of gas with the expected average cif price of LNG over the period ($17/GCal) points to a potentially large rent available to cover infrastructure costsUJ, this rent is quite sensitive both to load factor and cost of capital assumptions, as shown in Table 2.4. This table illustrates in particular the impact of a reduction in the cost of capital from 13X (GOK's official figure) to 8% (the figure actually utilized by KEPCO). At 8%, the available rent is reduced (from $10/GCal) to $5/GCal; the impact of this lower bound of the netback value of gas in the power sector on the viability of gas infrastructure investment is discussed in Chapter 3. Table 2.4 also illustrates the impact of load factor and coal price assumptions. The competitiveness of gas-fired combined-cycle plants is seen to improve significantly with a lower load factor as the impact of capital cost differential increases. On the other hand, alternative coal price scenarios have a limited effect on the viability of gas-fired plants. Table 2.4: Netback Value of Gas ($/GCal) Cost of Capital Load Factor 13X 8% Gas Coal 80% 70% 24 20 66.5% 58.2% 27 22 66.5% 66.51 24 20 501 501 28 23 Coal Price $55/ton 27 22 $45/ton 25 20 Z/ The economic rent available between the netback value of gas and the cif price of LNG is to be related to the cost of the infrastructure required to make gas available to the power plants, including regasification facilities and pipelines. This integration of benefits and infrastructure costs is being dealt with in the economic analysis presented in chapter 3. The proposed Il-Do combined-cycle plant will be located next to the proposed second LNG terminal and close to the end-point of the existing pipeline from Pyong Taek; the only relevant additional cost will therefore be that of the new terminal (about US$2/GCal). - 43 - 2.53 Additional sensitivity tests were conducted. They indicate (a) that comnbined-cycle technology is attractive as long as its capital costs are about $200/kW less than those of steam coal; and (b) that its attractiveness is relatively insensitive to changes in relative fuel efficiency parameters. The comparative economics of coal- and gas-fired power generation alternatives, however, will remain primarily dependent on future price trends. While present price forecasts (and technological factors) give the gas option a significant advantage, the evolution of world demand for coal and gas (primarily as fuels for power generation) may modify the current relationships. Since a gas import strategy (in part predicated on substantial use of gas in the power sector) would commit Korea for a long period of time, the possibility of a partial link between LNG and coal prices should be explored in the course of future gas import negotiations. Also, the strategy being followed by other countries facing similar circumstances, viz. to base power development on a combination of coal and gas plants (as well as nuclear facilities), would appear logical as a way of reducing risks from fuel price uncertainty. D. District Heating 2.54 District heating is a space heating method based on a centralized heat generating plant supplying urban areas with continuous heat through an insulated transmission and distribution network in lieu of the traditional, individual facilities. Due to relatively high distribution network costs, district heating applications are limited to countries with substantial space heating loads and relatively high urban densities. These conditions are met in a number of cities in Korea and district heating could, over time, provide for a substantial portion of the space (and water) heating needs of the urban population. 2.55 In general, district heating is deemed -:o be economical only in the context of combined heat and power generation vCHP), which offers the possibility of reducing space-heating costs by utilizing waste heat from electric power generation. By making use of relatively low temperature waste heat for district heating, CHP provides for a more efficient use of primary fuel inputs. Generally, a CHP plant will consist of an electric power plant located close (10-25 km) to urban areas W , and as such its viability will require that it fit well into the long-term electric power development program, especially with respect to choice and siting of intermediate load plants. 2.56 A number of district heating feasibility studies have been carried out in Korea over the past few years, and two sites (Mok-Dong and Southern Seoul) are already under development. An industrial estate cogeneration project has also been developed at Daegu. A district Heating Master Plan for the Greater Seoul area was completed in December 1986. j.Z/ Industrial cogeneration or waste heat sources are also possible. - 44 - The plan proposes three additional sites to install district heating facilities. The new systems would be linked progressively to the two existing ones to form an integrated district heating network. 2.57 CHP systems can be supplied from an existing heat source (i.e., a single purpose electrical power plant retrofitted for district heating purposes, or a refuse burning plant) or, in the absence of an available heat source, from a dedicated cogeneration power plant where heat and electricity are produced simultaneously. The two ongoing district heating projects in Seoul are supplied, in the case of Mok-Dong, from a dedicated oil-fired cogeneration facility linked to a refuse incineration plant and, in the case of Southern Seoul, from a rehabilitated (oil-fired) power plant. The Mok-Dong plant could be converted to gas-firing in the future out of environmental considerations. 2.58 The 1986 district heating master plan compares three fuel alternatives and two technology alternatives for future CHP systems: coal vs. HFO or gas; backpressure turbines vs. condensing extraction turbines. In all cases. steam from the turbine would be used to produce heat iln the form of hot water for district heating. Coal-fired CHF plants were found in the study to be both environmentally acceptable and to give the highest rate of return, compared both to oil and gas-fired plants. The study, however, fails to take account of (a) increased environmental concerns regarding the emission of pollutants in the Seoul area with correspondingly greater resistance towards the burning of coal (the study emphasizes correctly, however, that centralized CHP operations would lead to improved environmental standards compared to the burning of coal briquettes or fuel oil in individual facilities); and (b) the introduction of combined-cycle technology as a basis for new CHP systems, which leads to much higher returns on gas use. CHP systems based on a combined-cycle configuration have already been installed in Finland (city of Tampere) and in Holland (Den Haag, Leiden, and Pegus). Similar CHP systems for industrial use have also become widely used, particularly in the US. The comparative advantages of combined-cycle plants in generating electricity (based on present and anticipated LNG, oil and coal prices), which were discussed in the previous section, would equally apply to CHP systems. 2.59 The mission recommends that plans for future extensions of district heating facilities, in Seoul or elsewhere, take the gas-fired combined-cycle option into account in making configuration choices. KEPCO has already made tentative plans along these lines, together with the Korea District Heating Corporation (KDHC), for CHP units that would supply new urban developments in Il-San, Bun Dang and Pyung-Cheon outside Seoul. These plants would be dedicated primarily to the supply of steam (or hot water) for heating, with surplus power being essentially a by-product to be transferred to the grid (as under standard cogeneration sale agreements). An assessment could also be made of the feasibility of retrofitting the combined-cycle power plants KEPCO proposes to install at Incheon to support local district heating schemes. This could be done without significant reduction in operating flexibility if the plant is equipped with auxiliary - 45 - boiler(s). This approach could provide an economically attractive, if partial, solution to residential heating requirements in the Incheon area. 2.60 From an economic standpoint, the exact configuration of CHP plants should be a function of the relative values of steam and electricity. In practice, however, institutional issues will probably have a direct bearing on the choice of plant configuration, with electricity production or steam production being given greater emphasis depending on whether the plant is managed by the power utility or by a district heating utility. If CHP plants are designed as extraction-condensing power plants, they would automatically produce their maximum electricity output during the time of minimum heat demand. Electric power would be the main product and the heat in the wintertime a byproduct. As such this type of plants would be better suited for KEPCO's direct operation and ownership with steam sold to a separate district heating entity for distribution. 2.61 Apartment house complexes provide the main potential for district heating schemes. Based on future construction plans in seven major cities, the future total heat load of apartment complexes which could be hooked to a district heating system has been estimated at 5,260 MW(th) (4,540 Gcal/h) in 1990 and 8,000-11,000 MW(th) (7,000-10,000 Gcal/h) by the year 2000. Two thirds of this potential is expecced to be in the Seoul/Incheon area alone. It is difficult to anticipate the rate of penetration district heating systems will be able to achieve towards this potential. A number of factors will affect the outcome, including (a) institutional issues related to the integration of CHP systems in power system planning on a large scale; (b) technical factors such as the proportion of apartments equipped with individual heating systems (as opposed to central heating); (c) the relative cost efficiencies of district heating systems with individual systems based on gas or other fuels. Environmental issues are also likely to become increasingly prominent and may eventually lead to a comparison between individual gas-based heating facilities and gas-fired CHPs presumably based on combined-cycle configurations. 2.62 Two avenues are therefore available to introduce or expand the role of natural gas to meet space heating loads: as a fuel source for individual heating facilities (in individual dwellings, apartments or commercial buildings) or, alternatively, as a fuel source for centralized CHP/district heating systems. A generic comparison of the two options is - 46 - hardly feasible because of the multiplicity of site-specific factors involved. Tentative calculationsW indicate however that district heating systems are likely to have a comparative advantage, at least in such cases where generating plants can be located reasonably close to the areas to be supplied. District heating planning is still at an early stage. However, given the potentially large-scale use of gas this activity may generate, it is essential that current studies (by KEPCO and KDHC) be integrated rapidly within KGC's current gas infrastructure planning exercises. E. Environmental Issues 2.63 A key government objective in promoting the use of LNG is to reduce air pollution in urban and highly industrialized areas. This approach parallels similar trends in many other countries where environmental concerns have become a major determinant in the choice of energy options and increasingly influence the direction of energy investment programs. As discussed in Chapter 1, major current issues associated with the burning of fossil fuels include SO2, NOx, particulates and carbon oxide emissions. CO2 emissions are also receiving increasing attention in relation to global warming concerns. Natural gas, which is free of most pollutants present in liquid and solid fuels and generates only a fraction of the CO2 output of alternative fuels, can play a major role as part of a pollution control strategy. In particular, natural gas has no sulfur content and gas burning minimizes emissions of NOx and ozone. Accordingly, a key government objective in importing LNG has been to reduce air pollution in urban and highly industrialized areas. Following similar measures elsewhere, stricter emission standards have been set in Korea, particularly for SO2 emissions. By adding to energy costs, such environmental control measures influence the competitive position of alternative energy sources. One may therefore expect the tightening of environmental controls to progressively improve the competitive position of gas, both from an economic and financial standpoint. 2/ In general, district heating distribution costs would be about 3-5 times higher than gas distribution network costs for a typical, large apartment complex, partly because two pipes are usually required (supply and return) and the pipes need to be insulated and are usually of larger diameter. Costs are about $250-500/m for sub-distribution lines. For apartment blocks of the density typical in Korea, distribution network costs are about $80-90,000/MW(th), which would translate into unit costs of about $7-8/MWh(th) ($6-7/GCal), including maintenance and pumping costs (1 MW(th) - 1.16 Gcal/h). Transmission costs are a function of distance and quantities. For distances of less than 10 km between the CHP plant and the consumption area, the cost of the transmission lines, together with that of the main distribution grid, is estimated to add about 10-20X to the distribution costs. At a transport distance of 30 km, this ratio would increase to about 1:1. By way of comparison, average gas network costs for a typical, new apartment complex are estimated at about $6/GCal. 2.64 'n several countries, adoption of measures designed to regulate coal and HFO use are seen to have led to changes in gas utili7ation patterns, particularly itn the power sector. Thus, in Japan, the rising costs of coal-fired plants because of new environmental regulations have figured prominently in the power utilities' decision to turn to LNG. In the United States, the repeal of the Fuel Use Act makes investments in new gas-fired generating plants possible and there is a widespread expectation that a large share of future capacity additions will consist of gas-fired plants. Similarly in Europe, pressure is mounting to amend EC regulations that restrict the construction of new gas-fired pow'er plants. Although KEPCO has so far been little affected as yet by formal government regulations as regards fuel choices, the situation is changing and public pressure vis-a-vis coal-fired plants is also felt increasingly acutely. 2.65 For a number of end-uses, the economics of gas utilization are marginal when compared to alternative fuels on a strictly econom4c basis because of the high cost of LNG. In many cases, however, differences in en-7ironmental impact would considerably strengthen the justification for using natural gas. This includes substantial portions of the commercial and industrial markets. The main issues for the Government are (a) to determine the extent to which gas use should be encouraged beyond the levels dictated by commodity prices and efficiency factors; and (b) to identify the most effective way of providing the needed incentives (subsidies for conversion, cross-subsidy in price) and disincentives (taxes on polluting fuels, etc) to facilitate gas penetration of targeted markets. 2.66 GOK has so far relied mainly on fuel allocation policies in addressing environmental issues, in particular through the issuance of fuel use regulations specifying minimum fuel quality or altogether barring the use of certain fuels in some areas (e.g., liquid fuels by commercial consumers in downtown Seoul).W While these regulations are well- motivated, the issue is one of cost effectiveness and, for our specific purpose, of the comparative advantage of promoting the use of natural gas to address specific environmental concerns. As environmental issues gain greater prominence in the setting of energy policies, the Government needs to ensure that its policy decisions are rooted in an overall pollution 2W Currently much of the demand for LNG-based city gas is driven by environmental regulations. In Seoul, new power, industry and commercial facilities can no longer use coal. And in the downtown area of Seoul, when and where city gas is available, all commercial heating end-users of boiler size (output) greater than 2 MT/hour are required to switch to LNG city gas. The assumption is that these facilities would be switching from Bunker-C (or coal). The regulations on household use are unclear, but apparently Bunker-C (as well as diesel) can still be used in residential applications. Apparently coal can be used in residential applications as well, although it appears that for apartments this is only true for existing users; with respect to single family users, it is unclear whether continued use of coal is only for existing uses while not allowable for new construction. - 48 - control strategy supported by a proper assessment of available alternatives. While the analysis conducted as part of this study provides a number of relevant indications, more analytical work will be required to develop a comprenensive set of policies on environmental issues.1V There are three priority areas where gas can play a critical role in reducing the pollution impact of energy use, although rationalization of government policies will be a prerequisite to the establishment of fuel use patterns that properly account for the relative social costs of each fuel: (a) the use of HFO in the power and industrial sectors; (b) the use of HFO in the urban, commercial sector; (c) the use of anthracite for space heating. As discussed further below, each area will call for a specific set of measures: for large-scale energy users, a number of alternatives are available; hence, user-specific regulations on allowable emissions would probably be the most efficient approach, leaving each user the choice of the preferred means of meeting set emission targets. For commercial users (and apartment buildings), a tax on polluting fuels, combined with a tightening of standards on acceptable fuels, would be preferable to mandatory fuel switching regulations; taxes could be used to reflect the actual economic costs of alternative fuels, thereby relying on market P forces to elicit the optimum fuel use pattern. Finally, in the case of anthracite users, more direct government intervention, in the form of incentives to promote fuel switching, will be required (para. 2.77). 2.67 In comparing available energy options from an environmental standpoint, it is appropriate to differentiate between large-scale facilities for which emission control measures are both technically feasible and often cost-competitive, and smaller facilities for which cost issues rapidly become the most constraining factor. A number of techniques of emission control are commercially available for coal and HFO-burning facilities, with the most effective methods (flue gas treatment) being able to reduce SO, and NOx emissions by up to 80-90. Flue gas desulfurisation (FGD) is the most widespread method of SO emission control. The most common techniques for NOx control are low-NOx burners and combustion control measures; selective catalytic reduction (SRC) offers a more effective but also more costly approach. IQ/ In particular, there is a need to relate the additionLl cost of gas compared to cheaper but more polluting fuels with the cost of reducing the environmental impact of these fuels through other means, including fuel switching to a less polluting fuel (e.g., from HFO to low sulfur fuel oil or diesel oil), even though gas would still be a far cleaner fuel. Ideally, for each relevant end-use, an economic analysis would need to be conducted to assess whether similar environmental goals can be achieved at less expense. - 49 - Power Sector and Other Large-Scale Users 2.68 Environmental controls assume an increasing proportion of the cost of power plants, the ratio being a function of fuel quality and local regulatory requirements. To bring S02 emissions within environmental standards, new coal-fired plants in Korea are now equipped with FGD units. Because of the availability of low-sulfur coal at little or no premium over high-sulfur coal, FGD used to be considered an unnecessary addition to coal units; they now are included in KEPCO's planning as a matter of routine. 2.69 As discussed earlier, one of the most significant advances in electricity generation technology in recent years has been the introduction of gas-fired combined cycle processes. Besides their added efficiency, a significant advantage of these processes is that it provides for the high environmental performance of natural gas over alternative fuels: SO2 and particulates emissions are essentially eliminated while NOx (and C0O) emissions are reduced significantly. Moreover, while gas-fired combined- cycle plants may eventually require SCR for NOx control, SCR costs would be significantly lower than for a coal plant (about $15/kW vs $55/kW).!,/ 2.70 Despite the availability of technologies to mitigate the environmental impact of conventional coal- (and oil-)fired steam plants, it is unclear whether such plants will gain sufficient public acceptance for KEPCO to implement its proposed expansion program, which calls for the installation of seven coal plants with a total capacity of 5,100 MW over the next 12 years. A (partial) shift to gas is warranted by the encouraging results of comparative economics. Two factors could over time affect this general recommendation: a drastic change in relative price trends (of LNG vis-a-vis coal) from current expectations; and further progress in power generation technology, which is very much in a state of flux in response to environmental concerns worldwide. For these reasons, the Government needs to keep abreast of progress made in the development of various advanced (coa:- and oil-firing) power generation technologies, which offer the potential for important environmental gains going beyond the protection offered by FGD/SCR in conventional plants. These include DJ NOx emissions can also be reduced (at a lower cost) through steam injection in the gas turbines. So far only Japan and Germany have enacted NOx control legislation making SCR necessary. notably (a) fluidized bed combustion (FBC) systems R/; and (b) integrated gasification combined-cycle (IGCC) systems.1V 2.71 IGCCs provide for the conversion of coal to a highly combustible synthesis gas, composed mainly of carbon monoxide and hydrogen, and free of most pollutants, which is then combusted in a combined cycle power plant. IGCC technology, which is already available on a commercial scale,tM is a highly effective way of reducing the SO2 and NOx output of coal-fired stations while taking advantage of combined-cycle efficiency. As such, it is dfemed one of the most promising advanced technologies for the future. IGCC technology probably is the most relevant long-term alternative for Korea and provides a suitable comparison for gas-fired systems for the purpose of long-term system planning on a more or less environmentally equivalent basis. On the basis of current coal gasifier costs and efficiency iV, the break-even price of gas above which IGCC would become attractive would be 1.25 times the price of coal, plus a mark-up of about I/ FBC systems comprise (i) atmospheric fluidized bed combustion (AFBC), which is growing in commercial use although facilities are still limited in size; and (ii) pressurized fluidized bed combustion (PFBC), which is entering the commercial demonstration stage. FBC systems have been developed primarily to burn substandard fuels and are expected to emerge as an economical alternative for high-sulfur coal. After a tenuous start in the early 1980s, FBC technology is now being used in some 12,000 KW of capacity worldwide where its main advantage lies with its very broad fuel flexibility. It is based on the use of dry limestone, which results however in a large solid-waste problem, especially with high-sulfur fuels. jL/ A number of other technologies are also being developed such as fuel cell systems. At this point of time, however, these technologies have not yet reached sufficient levels of efficiency in relation to capital costs to make them an attractive option for Korea at least within the time horizon being considered here. 34/ Efficiencies of 42X are currently achievable (at capacity of up to 250 MW). The technology offers significant improvement prospects over the next decade, both at the gasifier stage (which would improve its competitive position vis-a-vis gas-fired ccmbined cycle plants), and in the generation cycles. Overall (gasification-combined cycle) efficiencies of about 45X could be attainable in the next few years. 12/ The capital costs of coal gasifier are currently about $1,000/kW (of final generation capacity), for an efficiency of 80X. O&M costs are about UScO.9/kWh (in addition to USc0.4/kWh for the combined-cycle portion of the plant). However, plant parameters vary from coal to coal. While, from a technical viewpoint, all types of coal can be gasified, the economics of gasification will vary from coal to coal. Moreover, IGCCs have a substantially lower availability than gas-fired combined cycles (about 701 vs. 931). 51 $17/GCal (assuming a 70X load factor). On the basis of our (discounted) average price of (delivered) coal of $8.5/GCal, this would place the break- even cost of gas at about $29/GCal. This is significantly higher than the forecast average cost of gas (after regasification) -- but close to the netback value of gas measured against conventional coal plants, which indicates that, as a coal technology, IGCCs would be economically attractive as soon as designs have been scaled up to standard plant sizes. One should expect significant reduction in the costs of coal gasifiers as the technology gains wider acceptance (initially in low-cost coal producing countries). However, the capital and O&M costs of coal gasifiers would have to drop by as much as 551 (all other parameters remaining the same) for IGCC systems to become attractive for a country like Korea importing both coal and gas.AV Gas-fired combined-cycles are therefore expected to remain the most attractive option for at least the next decade. 2.72 A separate issue relates to the choice of fuel in existing oil- fired thermal plants. KEPCO has been requested by the Government to convert a number of its oil-fired power plants located in densely populated areas, including the Incheon plant, to continuous gas-firing. However, the issue of whether this would result in a cost-effective handling of pollution control and LNG load balancing objectives is open to question inasmuch as substantial pollution abatement could still be achieved by having these plants occasionally run on low-sulfur fuel oil (to help meet seasonal variations in other markets), even though gas clearly provides a far cleaner fuel. As discussed further in para. 3.17, we recommend that mandatory fuel-switching policies in the power sector be reviewed to ensure that they provide a cost-effective answer to environmental objectives. Small-Scale Energy Consumers 2.73 Emissions from small-scale energy consumers, including small- and medium-sized industrial (SMI) facilities, commercial facilities for space heating, ane residential consumers, are generally more difficult to control than emissions fro- large energy users. While efficient and relatively cost effective p;st-combustion pollution control techniques are available for large power generation and industrial facilities, their costs rapidly become prohibitive as the scale of operations diminishes, which limits their use for smaller energy users. Generally speaking, the only options available to reduce the emissions of small-scale users are to shift to higher-quality fuels, modify the combustion process, which, however, is not as environmentally effective as the use of FGD and SCR, or centralize combustion in common facilities to facilitate emission control. .26 Combined-cycle plants can later be combi..zd with a front-end coal gasifier to produce an Integrated gasifier-combined cycle (IGCC) system, should the relative prices of coal and gas and the capital cost of coal gasifiers justify it. - 52 - 2.74 The fuel of choice forkboiler use by industries or for commercial and community space heating is HFO with normally a maximum sulfur content of 1.6Z, which is available from local refineries. Use of natural gas as a direct HFO substitute in boiler applications would in effect eliminate (or sharply reduce) all toxic emissions but may not be the most cost-effective method of reducing the environmental impact of small- and medium-sized industries -- and would be impractical under the existing price structure. Following similar trends elsewhere, the Government is now contemplating imposing further reductions in the sulfur content of fuel oil. This would probably induce a shift toward light fuel oil as refineries may find it difficult to produce large quantities of HFO with a significantly lower sulfur content than presently, especially in view of the rising trend toward heavier crudes worldwide, particularly in the Asia region. Alternatively, low-sulfur crude oil can be used in lieu of heavy fuel oil, as by some utilities in Japan, since the costs of desulfurization of heavy fuel oil currently outweigh the additional cost of light crude. In any case, a tightening of HFO specifications would result in higher fuel prices and probably a diminution in available supply. Industrial users would therefore be faced with the choice of using more expensive low-sulfur fuels or switching to natural gas, In such circumstances, one would expect the trend towards increased gas use in the industrial sector to accelerate. 2.75 An alternative approach to the use of gas as a straight boiler fuel would be to promote its use in the cogeneration of steam and power in CHP facilities, which can achieve environmental as well as efficiency benefits. Cogeneration can be effected either in plant-specific units or in larger-scale utility systems designed to supply industrial parks (in an approach similar to that of district heating systems). In either case, natural gas would be the most attractive fuel. Compared with separate power and steam production, decentralized cogeneration units (in SMI and commercial applications) would generate substantial fuel savings, thereby justifying more easily a switch to natural gas as the preferred approach to pollution control. The availability of efficient small-scale cogeneration units for commercial and SMI applications also need to be promoted. 2.76 In general, centralization of combustion facilitates the control of emissions. This is an important justification for setting up centralized CHP plants to supply industrial parks or district heating systems in urban areas. In the case of CHP plants located in urban or highly industrialized areas and burning coal or oil, current environmental regulations would in effect make the use FGD and possibly SCR technology mandatory. At any rate, reliance on coal- (or oil-)based CHP plants for district heating, as was recommended by earlier feasibility studies, would appear to run counter to current government thinking on acceptable fuel choices. However, the alternative offered by gas-fired combined-cycle plants retrofitted for dual power/heat production is both economically and environmentally attractive (compared to standard coal- or oil-fired CHP plants). Such plants combine the advantages of combined power/heat production, the efficiency of combined-cycle configuration and reliance on a clean fuel suitable to an urban or highly industrialized environment. They probably are the most efficient way to mitigate the environmental impact of SMI in areas with sufficient concentration of production - 53 - capacity. As such, centralized CHP facilities in industrial parks could gain greater prominence in the Kotean industrial sector and in turn provide a substantial and attractive market for gas. We recommend that suitable institutional arrangements be identified to facilitate the establishment of gas-based industrial utilities in areas with large SKI concentrations. 2.77 Residential Consumers. One of the most vexing environmental problems faced by the Government is that of anthracite-burning for residential space heating for which, as discussed in para. 2.20, there is no clear economic justification. Gas has clearly a role to play in addressing this issue although substantial government intervention would be required. The most promising avenue would be to encourage fuel switching through financial assistance to consumers towards the cost of conversion. High-efficiency household-sized boilers have been developed, which would minimize retrofit costs and whose availability should be promoted. The development of district heating systems could also provide part of the solution, although the technical feasibility of such systems in urban areas with traditional habitat at a reasonable cost is unclear and would need to be assessed. If technically feasible, CHP/DH systems could be expected to provide an effective way of mitigating the environmental impact of energy use while also bringing about a more rational fuel utilization. 3. SUPPLY-DEMAND SCENARIOS 3.1 KGC has made preliminary plans to expand gas supply in Korea. To evaluate the economic viability of this investment program, alternative supply/demand scenarios were developed based on plausible assumptions about future gas use. For this purpose, Korea can conceptually be divided into two separate regions, i.e., the region north of Pyeong Taek (i.e., the Kyongin region), where a gas system is already in place although many areas are not yet supplied (nor would it be necessarily economic to supply them); and the region south of Pyeong Taek where no gas system is as yet available. The southern area can be further divided between the central (Chungchong) region, the southeast (Yongnam) region, which includes the highly industrialized Pusan/Ulsan area, and the less developed southwest (Honam) region (See the attached map). Supply-demand scenarios were developed for each region separately. 3.2 As is clear from the gas utilization analysis, the development of combined-cycle technology for power generation, associated with the availability of a reliable supply of gas, have introduced new dimensions to the future of the LNG industry in Korea. The original focus on coal replacement in large cities has been superseded by the possibility for LNG to make a major contribution to overall energy supplies, with the power sector assuming a central role in the definition of LNG facilities: overall, gas use is expected to be divided between power and non-power users approximately in a 60-40 ratio. - 54 - A. The Residential, Commercial and Industrial Markets 3.3 A pertinent evaluation of potential gas demand must reflect both economic and financial end-use analysis. In actual fact, however, future demand will be largely supply driven (by the pace of construction of gas infrastructure); demand will be also strongly influenced by housing development schemes and by whether or not needed regulatory and institutional action takes place. The basis for our demand projections is the KEEI Gas Demand Study (para. 1.26). The results of this study, which is based on a careful analysis of macroeconomic trends, were crosschecked and modified as required in the light of the end-use analysis reported in Chapter 2. Also, correlations with anticipated programs of housing construction and industrial activity were elicited. In general, these demand projections appear reasonable as a starting point for a preliminary review of investments. 3.4 The KEEI demand projections, however, lack the underpinning of discrete market surveys, particularly as regards industrial demand. As discussed in para 3.38, the undertaking of such surveys on a selected basis, together with basic gas system design studies, is a critical prerequisite to the implementation of an expanded gas strategy. Market surveys for industry should focus on the textiles, food processing and metal industries which should provide for a high-value gas market. 3.5 The end-use analysis also underscores the potentially critical role to be played by CHP plants to supply district heating systems and industrial utility systems. It was not possible, however, to disaggregate the possible contribution of these two categories of gas users from the broader categories of residential space heating demand, on the one hand, and industrial deaand, on the other. From a system planning point of view, however, a detailed survey of these discrete consumers is in order. Finally, much uncertainty remains in regard to future government policies in the area of fuel use and related energy pricing, which would have a direct bearing on future demand. While the demand projections are based on plausible assumptions regarding gas penetration of each market, much needs to be done to establish the policies and institutional mechanisms necessary to enable gas penetration of preferred markets, as discussed in Chapter 4. 3.6 Forecasts of gas demand in the residential, commercial and industrial markets are shown in Annex 9 and summarized in Table 3.1. 55 - Table 3.1: City-Gas Demand Forecast (in million cu m) 1989 1991 1996 2001 2006 Residential 144 215 412 733 1,070 Commercial 126 212 373 591 806 Industrial 157 265 460 590 716 Subtotal 427 692 1,245 1,914 2,592 Chungchong Residential - - 61 153 285 Commercial - - 56 127 217 Industrial 45 71 96 Subtotal - - 162 351 598 Yongnam Residential - - 98 242 439 Commercial - - 98 215 347 Industrial - - 131 304 524 Subtotal - - 327 761 1,310 Honam Residential - - 22 118 220 Commercial - - 23 105 174 Industrial - - 45 148 262 Subtotal - - 90 371 656 Residential 144 215 593 1,246 2,014 Commercial 126 212 550 1,037 1,544 Industrial 157 265 681 1.114 1.598 Total 427 692 1,824 3,397 5,156 (m. tons of LNG) (0.4) (0.6) (1.5) (2.9) (4.4) Sources: KEEI, KGC and mission estimates. B. Demand from the Power Sector 3.7 The comparative economics presented in Chapter 2 indicate that, while current use of gas in existing thermal power plants is hardly justified except out of environmental concerns, its choice as a fuel for new power plants is economically attractive both on efficiency and environmental grounds. Actually, electricity generation is the main avenue by which LNG is expected to make a major contribution to Korea's overall energy supplies. In addition to (or in lieu of) its current role as a "swing" consumer, KEPCO is now considering a major expansion in LNG-based. Besides the large economic benefits this will generate, continued high demand from the power sector is important as it will facilitate the handling of seasonal variations in gas demand by matching the city gas - 56 - companies' and KEPCO's mutually exclusive load curves -- summer peak for power and winter peak for gas. 3.8 Future gas demand from the power sector falls under three broad categories: (a)plants acting as swing consumers to absorb any surplus quantities of LNG that would have been contracted at any point of time (particularly during summer months); (b)existing oil-fired plants to be converted to gas out of environmental concerns; and (c)new gas-dedicated (combined-cycle) plants. HFO Substitution in Existing Power Plants 3.9 Gas use in thermal plants originally designed for oil-firing is expected to remain substantial, mostly on account of environmental control objectives. Since LNG deliveries started in 1987, regulations on the type of fuels for power plants located in the Seoul metropolitan area (including Incheon) have been tightened and the Incheon plant, which was converted to gas in 1987 to absorb the initial quantities of LNG, is now expected to remain on gas-firing on a continuous basis. Similarly, the Seoul and .-yongin thermal power plants would be converted to gas starting in 1994. In addition, one of the four units of the Pyeong Taek power plant will also have to remain on gas on a continuous basis because of the need to utilize boiler gas from the terminal's vaporizer, which cannot be fed into the trunkline. 3.10 KGC's demand forecast for the southeruk regions envisages the conversion to gas of the Ulsan power plant (units 3,4 and 5) and the Youngnam power plant, under the assumption that environmental policies in force in the Seoul area would equally apply to the highly industrialized Pusan/Ulsan area, should gas be made available there in the future. 3.11 Our base-case demand projections are predicated on the above understanding of KEPCO's conversion plans. To capture the environmental benefits derived from the use of gas in lieu of HFO in urban areas, the price of low-sulfur fuel oil is used as a proxy (which underestimates the extent of pollution control achieved through fuel switching). New Combined-Cycle Power Plants 3.12 As discussed in Chapter 2, gas-fired combined-cycle plants offer the best opportunity for economically efficient use of imported gas in the power sector. This general assessment, however, is based on a generic - 57 - comparative analysis of alternative generation options, and the scope for this type of facility in Korea can only be established through a system planning analysis. The present situation of the power system is characterized by rapidly growing demand in the Kyongin region where 40X of total electricity demand already originates, and surplus power supply in the south, particularly the Honam region; by comparison, the power supply/demand situation in the Yongnam region is pretty much in balance. Since most of the available sites for future coal and nuclear plants are located along the southern and southeastern coastlines, the need to transfer large quantities of electricity from south to north will go increasing unless generation capacities can be installed in the northern part of the country. This is an Laportant reason for KEPCO to consider the possibility of installing large combined-cycle capacity close to its major Seoul market. The need for similar facilities in the south is clearly not as compelling, at least for now, but would need to be reviewed carefully in a power system planning context (particularly to assess intermediate load requirements). 3.13 KEPCO's latest power development program provides for the phased erection of a 4x800 MW combined-cycle plant on the island of Il-Do close to 1-icheon. The first phase is expected to come on stream in 1992, with the subsequent phases following in 1996, 2000 and 2004, respectively. KEPCO has also made preliminary plans (together with KDHC) for the construction of three gas-fired CHP plants (also based on combined-cycle technology) with a total capacity of 775 MW to supply new urban developments in the Seoul metropolitan area (i.e., Il-San, Bun Dang and Pyung-Cheon). 3.14 Since construction of a gas grid to supply the southern part of the country is still under discussion, plans for installing new gas-fired power and CHP capacity outside the area served by the existing gas system are naturally less advanced. However, as discussed below, it would be difficult to justify the construction of a gas grid to the south without the support of a substantial power-CHP program. To help provide a framework for the evaluation of trade-offs, the mission developed an alternative power demand scenario for the southeastern (Yongnam) region; this scenario is meant to illustrate the minimum demand from KEPCO that would be required to justify the construction of a national gas grid. 3.15 The capacity and location of power plants will have a major impact on the timing, sizing and location of LNG facilities (terminals and main transmission lines). Given the relevance of power investment decisions (including CHP facilities) in planning future gas infrastructure, uncertainties surrounding power planning should be lifted as soon as possible. Accordingly, we recommend that the Government consider the establishment of a consultative gas planning working group to strengthen the coordination between the planning activities of KGC, KEPCO and KDHC (para. 4.4). - 58 - Swing Consumers 3.16 The role of swing consumer is now assumed by the Pyeong Task and Incheon power plants, which together accounted for 911 of LNG consumption in 1988. This ratio will decrease as city-gas markets develop. The need for swing consumers will remain, however, in order to handle (a) seasonal variations in non-power demand; and (b) the quantum jumps in LNG deliveries as additional import quantities are being contracted out. The magnitude of "swing" consumption will depend on several factors, including the size of future LNG contracts, KGC's ability to offset the seasonality of power and non-power demand, and the extent to which future LNG contracts would provide for added flexibility in the schedule of LNG deliveries (or whether spot purchases of LNG can be effected to meet winter peaks). 3.17 As indicated in para 2.71, KEPCO has beea requested by the Government to convert a number of its oil-fired power plants (located in or close to densely populated areas) to continuous gas firing. Accordingly, KGC's (and KEPCO's) supply/demand forecast assumes that these (converted) plants could therefore not be considered as swing consumers (i.e., the eventuality of a gas supply interruption is not an acceptable planning assumption). However, such use of gas on a continuous basis would entail a significant economic cost which probably exceeds the additional environmental benefit of not using low-sulfur fuel oil even on a teporary basis. The issue arises as to whether some of these "converted' power plants could not assume part of the swing function required by the system. Such an approach, which would be highly cost effective by reducing the extent of uneconomic gas utilization elsewhere (e.g., at Pyeong Taek), could be complemented by a contribution from KEPCO towards the cost of environmental control measures in higher priority areas (reflecting the temporary fuel saving achieved by shifting from natural gas to low-sulfur fuel oil). We recommend that mandatory fuel-switching policies in the power sector be reviewed to ensure that they provide a cost-effective answer to environmental objectives. Gas Demand Scenarios 3.18 Projections of gas demand from the power sector are summarized in Table 3.2. The table shows both the projections currently assumed by KGC whose plans do not provide for any use of gas for power generation outside the Kyongin region, and an alternative scenario developed by the mission, which provides for a broader-scope power/CHP construction program, together with use of gas in some existing plants, in the Yongnam region. - 59 - Table 3.2: Power Sector Demand Scenarios (in thousand tons of LNG) 1989 1991 1996 2001 2006 Kyongin Existing Plants 1,639 1,414 1,694 1,579 1,054 Combined-Cycles - 1,252 1,902 3,203 Yongna a/ Existing Plants - - - 48 1,026 Combined-Cycles - 585 910 910 Existing Plants 1,639 1,414 1,694 1,627 2,080 Combined-Cycles - 1.837 2.812 4.113 Total 1,639 1,414 3,531 4,439 6,193 a/ Alternative Mission Scenario C. Main Infrastructure 3.19 The existing basic gas infrastructure, which consists of the Pyeong Taek terminal and of a main trunkline from Pyeong Taek to Seoul/Incheon, is sufficient to accommodate the LNG deliveries provided for under the existing contract. This basic infrastructure could be strengthened and/or expanded to accommodate a measured increase in gas deliveries. However, very substantial investments would be required if the decision is taken to expand LNG imports much beyond the original contract. 3.20 In terms of future demand, KGC is faced with the following circumstances: (a) a growing city gas market in the Seoul/Incheon area, which will require strengthening rf the Seoul loop over time; (b) additional demand from KEPCO for the new combined-cycle plant at Il-Do; (c) a potential city gas market south of Pyeong Taek (i.e., in areas hitherto not serviced by KGC's existing gas system); and (d) possible demand from KEPCO for existing or new power units south of Pyeong Taek. - 60 - Taking these possible market developirents into account, KGC has prepared a preliminary "LNG Supoly Study." This study provides a conceptual approach to system development with preliminary implementation schedules and cost estimates. These data provide the basis for the following discussion. Terminals 3.21 No detailed feasibility studies have been conducted as yet to fully substantiate a strategy for LNG terminal capacity expansion. The background information assembled by KGC to assess the potential for expanding the existing Pyeong Taek terminal and the feasibility of constructing a new terminal on Il-Do island at Incheon are therefore fragmentary and would need to be supported by detailed feasibility studies. They are sufficient, however, to express a judgment on the possible alternatives and chart a tentative strategy for future investment. The KGC study proposes the expansion of the Pyeong Taek terminal in two phases and, proceeding in parallel, the construction of a new terminal at Incheon. The need for a third terminal is not envisaged until the end of the study period (2007). 3.22 The existing terminal at Pyeong Taek is equipped with four storage tanks (4xlOO,000 cu m) and has a nominal capacity of 2 million tpy. It could apparently be upgraded to 3 million tpy capacity at relatively little cost. Further extensions would involve substantial expenses due to the need to install additional storage tanks. However, the site could not accommodate capacity expansions beyond 5.5-6 million tpy because of limited jetty capacity and lack of space for more than a total of six LNG tanks. 3.23 Construction of a second terminal, from the planning/design stage to start-up, is expected to take about seven years. On the basis of expected demand growth, a second terminal would be required by the mid- to late-1990s, depending on the demand scenario being considered. Preliminary preparation work would therefore need to start soon. In terms of location, the basic alternative is between a northern location (i.e., close to Seoul) and a southern location (close to the Pusan/Ulsan area). If the decision is taken to construct a national gas grid covering the southern regions, a southern site would present obvious advantages in terms of load balancing and could possibly reduce pipeline investment by lowering the long-term throughput between north and south. At least three factors, however, would argue against a southern site for the second terminal: first, demand in the southern districts is expected to grow more slowly than in the Seoul metropolitan area and, even under the most optimistic scenario, about 70X of total sales would still be realized in the north by 2007. A second factor is KEPCO's decision ta install a major gas-fired power plant close to Incheon. Given the magnitude of this plant's long-term fuel requirements (3-4 million tons of LNG), the construction of a .partialiy) dedicated terminal at Incheon is logical. A final consideration relates to the security of supply for the Seoul area, which is now entirely dependent on one single terminal and trunkline. Construction of a second terminal at Incheon would considerably alleviate security concerns and greatly improve - 61 - the stability of supplies to Seoul which will remain the largest gas market in Korea. 3.24 Present demand scenarios indicate that a third terminal would not be required before the end of the study period. Presumably, a southern coast location would by then be justified, assuming the earlier construction of a gas grid covering the southern districts. The alternative of an autonomous terminal in the south dedicated to the southern market was also considered but is not deemed cost effective mainly because it would not obviate the construction of additional terminal capacity in the north and of substantial pipeline in the south. Pipeunes 3.25 The program of pipeline construction required to meet the alternative demand scenarios includes (a) reinforcement of the existing system north of Pyeong Taek; and (b) construction of trunklines south of Pyeong Taek. KGC's LNG Supply Study provides a preliminary concept analysis of the modifications required to expand the delivery capacity of the system, assuming that expansion of terminal capacity would proceed as described in para 3.21. KGC had earlier commissioned a feasibility study for a national gas grid designed to supply the southern districts with natural gas (para 1.25). This study recommended the phased construction of a pipeline system that would successively reach the cities of Taejon (1993), Daegu (1993), Pusan (1994), Masan (1994) and Kwangju (1996). Completion of the loop between Kwangju and Masan was proposed for a later: date together with the construction of a new terminal on the south coast. 3.26 Regional (national) gas distribution can take the form of a pipeline grid (such as exists in North America and Europe) or, alternatively, of "nodes' of gas distribution systems with local LNG regasification facilities supplied from the main receiving terminal by (road or possibly marine) tankers (as is also done in parts of the U.S. and Europe and in Japan). This alternative approach was studied by KGC and found less attractive than a pipeline grid as indicated in the previous paragraph. We recommend that the viability of delivering LNG to satellite terminals by tanker as a complementary approach to the stepwist construction of a grid be reassessed once key decisions on the basic infrastructure construction program have been taken. Detailed studies may indicate that temporary supplies of LNG by tanker could be attractive to those city gas systems which are not planned to be tied to the main grid until a later date. Early access to LNG would allow those companies to start expanding their sales beyond the traditional manufactured gas markets and plan the development of their network accordingly, which would reiuce long-term investment costs and facilitate the overall penetration of LNG in higher-value markets. 62 Supply Scenarios 3.27 Four alternative supply scenarios were developed in accordance with the geographical breakdown introduced in para 3.1: Scenario A would consist essentially of the strengthening and expansion of the existing system to accommodate the expected increase in demand from KEPCO at Incheon and other sites in the Seoul metropolitan area. This scenario would cover the northern area only (Kyongin region) and would require: (a) the extension of the Pyeong Taek receiving terminal to 3.5-4 million tpy capacity (5 tanks) by 1994 and 6 million tpy (7 tanks) by 2006; (b) the construction of a new terminal at Incheon with an initial capacity of 2 million tpy (3 tanks) by 1997 and an ultimate capacity of 3 million tpy (4 tanks) by 1999; and (c) the strengthening of KGC's existing pipeline system to accommodate the increase in gas flow and feed the new power and CHP plants. Scenario B would add to scenario A the (first-phase) construction of a trunkline to the south (Pyeong Taek - Taejon). This scenario would cover the northern and central areas (Kyongin and Chungchong regions) and would require: (a) the extension of the Pyeong Taek terminal to 3.5-4 million tpy capacity by 1994 and to 6 million tpy by 2006; 'b) the construction of a new terminal at Incheon with a capacity of 2 million tpy by 1997 and 3 million tpy by 1999; (c) the strengthening of KGC's existing pipeline system; and (d) the construction of a main transmission line from Pyeong Taek to Taejon (by mid-1993). u - 63- Scenario C, which would cover the northern and southeastern areas (Kuongin. Chungjhorg and Yonfanm regions), would consist of: 4) the extension of the Pyeong Taek terminal to 3.5-4 million _ tpy capacity (5 tanks) by 1994 and 6 million tpy by 2004 (7 tanks); (b) the construction of a new terminal at Incheon witn initial capacity of 2 million tpy (3 tanks) by 1996 and ultimate capacity of 3 million tpy (4 tanks) by 1998; (c) the strengthening of KGC's existing pipeline system; and (d) the construction of a main transmission line from Pyeong Taek to the s:!an/Ulsan area (via Taejon). Scenario D would provide for the phased construction of trunklines both to the southeastern and southwestern regions. This scenario (covering the Kyongin. Chungghong. Yongnam and Honam regions) would require: (a) the extension of the Pyeong Taek terminal to 3 5-4 million tpy capacity by 1994 and 6 million tpy by 2004; (b) the construction of a new terminal at Incheon with initial capacity of 2 million tpy by 1996 and ultimate capacity of 3 million tpy by 1998; (c) the strengthening of KGC's existing pipeline system; and (d) the construction of transmission lines from Pyeong Taek to the Pusan/Ulsan area (via Taejon) and from Taejon to the Kyongju area. 3.28 Details of the supply/demand profiles for the four scenarios are in Annexes 9 and 10; they are summarized in Table 3.3 below. An additional fifth scenario (Scenario Cl) is also presented, which has been designed as an alternative to Scenario C to accomodate the alternative power sector demand scenario introduced in para 3.14. - 64 - Table 3.3: Gas Supply Profiles (million tons of LNG) Scenarios A B C Cl a/ D Total supply: 1989 2.0 2.0 2.0 2.0 2.0 1996 4.0 4.2 4.4 5.0 4.5 2001 5.1 5.5 6.1 7.0 6.4 2006 6.5 7.1 8.2 10.0 8.9 Power Sector Demand: 1989 1.7 1.7 1.7 1.7 1.7 1996 3.0 3.0 2.9 3.5 3.0 2001 3.5 3.5 3.5 4.4 3.5 2006 4.3 4.4 4.4 6.2 4.5 of which Combined-Cycle Plants: 1989 - - - - - 1996 1.3 1.3 1.3 1.8 1.3 2001 1.9 1.9 1.9 2.8 1.9 2006 3.2 3.2 3.2 4.1 3.2 a/ Based on alternative power demand scenario for Yongnam region. Cost Estimates 3.29 Detailed cost estimates of KGC investments for each of the five scenarios are in Annex 11. They are summarized below: Table 3.4: Alternative Investment Programs a/ (in $ million) Scenarios A B C C1 D 1990-93 323 424 598 598 626 1994-97 427 432 574 574 808 1998-01 16 16 80 142 80 2002-06 liZ 162 90 118 90 Total 928 1,034 1,342 1,432 1,604 a/ Including taxes and duties but excluding interest during construction. 3.30 These cost estimates are based on the feasibility studies commissioned by KGC. They would need to be refined through detailed design studies as implementation proceeds. However, a preliminary review of these estimates in the light of experience in other countries indicates that there is room for cost-effectiveness measures, particularly in the design and construction of transmission lines. Such measures would be likely to entail substantial cost reductions which would facilitate the penetration of gas in the economy. D. City Gas Distribution .31 As indicated earlier, the Government's strategy has been to license private companies to establish city gas networks in selected urban areas to be operated in the first place on manufactured gas with a view to building up markets for LNG ahead of the start-up of actual deliveries. This is a sound strategy which has the double advantage of minimizing recourse on public resources in an area which is essentially a commercial activity, while ensuring access of high-value markets as soon as LNG deliveries started. However, a number of shortcomings in the way city gas companies have developed need to be flagged as they iApact directly on future sector planning and would have a number of important institutional consequences. 3.32 The main concern is that, while the government objectives in the sector are clearly long-term (10 to 15 years), partly due to the lumpiness of the investments involved and the characteristics of LNG contracts, the objectives of the gas companies are essentially short-term and do not necessarily match those of the Government. This is due to a number of factors, e.g.: (a) the planning capabilities of the gas companies, both in terms of marketing and technical design, are not geared to the long term and their planning horizon is at best three years; (b) although there is an association of city gas companies, the companies do not seem to exchange information about distribution network planning; (c) finally, it seems that the development plans of individual gas distribution companies are largely dependent on short- term financial objectives. This situation makes it difficult to reconcile the national objectives and those of the private utilities in the absence of an overall policy framework providing guidelines for the utilities and ensuring that overall objectives are met within the limits of economic and financial viability. This issue is further discussed in Chapter 4 (paras. 4.4-4.6). - 66 - Company Operations 3.33 The city gas networks were initially dsveloped to operate on manufactured gas. Because of the limited competitiveness of manufactured gas outside the traditional cooking market, little provision was made in developing these systems for the subsequent introduction of natural gas, which the Government expected to lead to a broadening of gas markets, in particular to address the space heating air pollution problem. As a result, network structures are poorly adapted to the development of important loads over large areas. The capacity of mains, which conditions the long-term capacity of the systems and their ability to expand over time, has in general been conservatively planned and reticulation of mains is little developed. The networks consist mostly of polyethylene (PE) coated steel pipes operating under a cumbersome multi-pressure system, with distribution lines designed for low-pressure operation only, which severely restricts the scope for additional loads. Finally, customer governors are generally of an outdated technology and ill-suited to industrial use. However, the city gas companies appear to have developed reasonably good network computing capabilities, and the overriding issue is more one of management and investment priorities than of technical know-how. 3.34 The construction costs of gas utilities in Korea are generally high compared to those in other countries. This is possibly due to local factors, such as difficulties in obtaining trenching permits and severe reinstatement regulations imposed by the municipalities and, more generally, excessive intervention of local authorities in planning, construction and safety issues. In addition, until recently government regulations precluded the use of polyethylene materials under medium- pressure operating conditions as is now the norm in most countries. The relevant code of practice, which insisted on low-pressure distribution networks necessitating larger diameter pipelines and with far less flexibility for subsequent expansion, was modified at the beginning of 1989. Recourse to medium-pressure technology should result in a progressive reduction in distribution costs, possibly by up to 20-30X. 3.35 The city gas companies normally invest in the mains and distribution lines while local distribution networks (i.e., within new apartment building areas) are left to the developers. The cost of investments downstream of the service connections (i.e., service lines, meters and regulators, as well as internal piping) is assumed by the customers. Investment financing does not appear to have been a problem so far, with the companies being able to draw on cheap (5X) government funds available through the Petroleum Fund. Part of these funds can be on-lent to customers to finance their own share of expenditures (internal piping, appliances, etc), which compensates to an extent for the conservative hook- up policy indicated above. - 67 - Estimated Costs of Fture City Gas Investments 3.36 Due to lack of long-term planning by the city gas companies, the magnitude of gas distribution investment required to meet the expected growth in non-power demand is subject to much uncertainty. The gas companies are requested by the Government to prepare three-year investment plans (on a rolling basis). However, because of the absence of long-term master plans, the extent to which past and present company investments provide for the construction of a main grid, which would generate economies of scale as markets develop, is unclear. This makes it particularly difficult to extrapolate from the available near-term figures. 3.37 With the help of KGC, the mission prepared projections of gas distribution investments for each of the four supply scenarios presented in the previous section (Table 3.5). These projections should be considered as very tentative and would need to be corroborated by conceptual studies (para 3.42). They are essentially based on linear forecasts of mains and service lines according to future demand. As such, however, they provide a rather conservative outlook of future needs, and therefore constitute a reasonable basis for the purpose of assessing the economic viability of sector investment. Table 3.5: Estimates of Distribution Costs (in $ million) Sicenarios A B C C1 D 1990-93 274 301 301 301 301 1994-97 222 252 437 437 493 1998-01 292 342 518 518 639 2002-06 287 352 560 560 668 Total 1,075 1,247 1,816 1,816 2,101 System Planning 3.38 The high degree of uncertainty on future distribution costs, which to a large extent derives from the role assumed by private investors in this segment of the industry, will affect the ability of the Government to chart a rational gas utilization strategy and formulate effective policies to implement this strategy, including pricing. Without questioning the merits of the government strategy to rely on private initiatives and resources in what is essentially a commercial activity, this element of uncertainty underscores the need to take a longer-term view of system development to rationalize the use of resources. Distribution costs alone are expected to amount to between one and two billion dollars over the next 10 years (or about 55-60X of total sector investments on a net present value basis), and will probably require a continuation of government 68 support on a significant scale. In view of the magnitude of these investments, we recommend that conceptual master plans for urban distribution networks, backed up by discrete consumer surveys, be prepared for the largest consumer concentrations, including (a) the Seoul/Incheon area; (b) the Pusan/Ulsan area; (c) a typical medium-density city (e.g., Taejon); (d) a typical low-density city. Consumer surveys should focus on industrial consumers, taking into account recent advance in gas utilization technology. These master plans could be completed within a period of six months to a year and at a cost of about $1 million, a very small amount compared to the investment program itself. KGC should take the lead in executing these studies in close collaboration with the utilities concerned. E. Economic Evaluation 3.39 This section presents the results of an economic evaluation of the four alternative investment scenarios described in Section C (together with the corresponding gas distribution component). The analysis is done on an incremental basis, taking the situation in 1989 as reference, i.e., previous investments are considered as sunk and the pattern of LNG usage in 1989 is taken as a starting point. Future investments (by KGC and the city gas companies) are expected to achieve the following objectives: (a) to increase the average end-use value of the quantities of gas available under the original contract by shifting their usage from existing thermal power plants (where they substitute low-value HFO) to city gas markets; and (b) to expand the overall supply of gas, in part in response to KEPCO's increased demand and in part (for Scenarios B, C and D) by broadening the geographical availability of natural gas to the southern regions. 3.40 Economic benefits are derived from the netback value of gas at the consumer (plant) gate, as discussed in Chapter 2. These netback values are based on the economic cost of the energy source being displaced, corrected for differentials in heating value, thermal efficiency, and the capital and operating costs of appliances and end-use equipment. Economic costs include the CIF price of imported LNG and all infrastructure investments by KGC (for reception, regasification and transmission) and the city gas companies (for distribution). The analysis covers the period 1989-2007. 3.41 Each alternative supply/demand scenario was measured against the original 1989 situation by calculating the net present value (NPV) of incremental costs and benefits. Since the four scenarios represent increasingly more ambitious investment programs, their viability should be assessed on an incremental basis (i.e., each additional investment should generate a higher NPV). The results underscore the high attractiveness of ScenariA with an NPV close to $1 billion. These positive results are due to a combination of factors: (a) the basic infrastructure for supplying Seoul is already in place and would only need marginal strengthening to support a substantial expansion in throughput; (b) as sales to city gas - 69 - users expand, gas use can be shifted from substituting low-value HFO in power plants to higher-value uses; and (c) high returns will be derived from the use of gas in combined-cycle units starting in the mid-1990s. 3.42 The analysis also indicates that Scenario B, with an NPV similar to that of Scenario A, would be an acceptable alternative; i.e., construction of a transmission line south of Pyeong Taek to the Taejon area would be justified, albeit on a marginal basis and subject to confirmation of estimates of distribution costs for the Taejon area (para. 3.47). 3.43 While Scenarios A and B are clearly attractive, the analysis indicates that Scenarios C and D would not be viable in the absence of substantial demand from the power sector, particularly in high-value end- uses (e.g., combined-cycle type of facility, including CHPs). Scenario C1 illustrates the minimum demand from KEPCO estimated to be required to justify construction of a trunkline to the Yongnam region. In brief, it is estimated that gas would have to be used in about 800 MW of new (combined- cycle) power capacity located in the south, as well as in a number of existing oil-fired units (about 1,500 KW), in order to justify the proposed trunkline investment. Note, nowever, that the investment could be justified with a lower demand from the power sector if substantial value is attached to the objective of reducing pollution in the highly industrfalized Pusan/Ulsan area!'-. The economic attractiveness of Scenario i is significantly more marginal than that of Scenario C because of the lower anticipated gas demand in the Honam region. The Government is considering far-reaching regional development plans for the western seaboard, partly through the establishment of industrial zones. These plans could have a significant bearing on future gas demand, particularly if the new industrial parks were to be equipped with centralized utility systems which would provide a convenient and economic market for natural gas. We recommend that plans to make natural gas available to the southwestern part of the country be reviewed after regional development plans have been firmed up and updated forecasts of gas demand are available. Note that the conclusions reached in regard to Scenarios B, C, Cl and D are largely dependent on the estimates made of future distribution costs. As indicated earlier, these estimates need to be corroborated by conceptual master plans for the key areas (i.e., Taejon and Pusan/Ulsan). 3.44 The results of the analysis (Annex 12) are summarized below: U/ Gas substitution for HFO in existing power plants in the Pusan/Ulsan area would generate substantial benefits through improved environmental conditions. The analysis presented here permits a preliminary evaluation of the costs of meeting environmental concerns through gas use, should GOK decide to go ahead with an investment program not fully justified from a strictly economic perspective. - 70 - Table 3.6: Net Present Value of Alternative Investment Programs (in $ m'llion) Scenarios: A B C Cl a/ D 13X Cost of CaDital Benefits Power Sector 3,096 3,168 3,133 4,171 3,150 Others 1.681 2.024 2.601 2.602 2.853 Total 4,777 5,192 5,734 6,773 6,003 Costs b/ LNG (CIF) 2,813 3,097 3,497 4,259 3,700 Basic Infrastructure 422 488 683 702 809 Distribution 549 615 819 819 914 Total 3.784 4.200 5.000 5.780 5.423 Net Present Value 993 992 736 993 580 81 Cost of Capital Benefits Power Sector 4,184 4,310 4,251 5,843 4,286 Others 2.710 3.301 4.340 4.340 4.802 Total 6,894 7,611 8,591 10,183 9,088 Costs b/ LNG (CIF) 4,630 5,125 5,847 7,220 6,225 Basic Infrastructure 550 626 861 892 1,025 Distribution 778 880 1.216 1.216 1.376 Total 5.957 6.631 7.924 9.328 8.626 Net Present Value 937 980 667 855 462 a/ Based on alternative mission scenario for power. b/ Capital and operating costs. 3.45 The results of the analysis were tested using a lower cost of capital (81). Prima facie, a decline in the cost of capital would ease the heavy investment burden associaLed with gas import and utilization. The implicit cost of infrastructure would go down and the economics of gas utilization in most residential, commercial and industrial applications would improve. However, as discussed in Chapter 2, a decline in the cost of capital would also lessen the comparative advantage of gas use for power generation vis-a-vis coal in conventional thermal stations, which hinges largely on capitai cost differentials. Because of the expected predominance of combined-cycles in the future pattern of gas use, this is a significant factor. Actually, both factors tend to cancel each other, with the present value of each alternative scenario showing little sensitivity - 71 - to variations in the cost of capital (although this becomes an increasingly relevant factor as one moves towards more capital-intensive scenarios, e.g. C and D). This, however, does not eliminate the relevance of the cost of capital in defining a gas utilization strategy for Korea since differing capital cost burdens would affect the distribution of the available rent among consumers, with important pricing and other implications. 3.46 The impact of alternative LNG price hypotheses is also instructive. The net present value of the four alternative supply/demand scenarios was tested with the three LNG price variants introduced in para. 1.58. Table 3.7: Impact of LNG Prices (NPV in $ million) LNG Price Scenarios a/ Investment Scenarios I II III IV A 993 1,113 1,242 1,223 B 992 1,124 1,266 1,246 -, 736 885 1,045 1,026 Cl b/ 993 1,175 1.370 1,352 D 580 737 907 888 a/ See para 1.58 and Annex 5. b/ Based on alternative scenario for power sector demand. While lower LNG prices would obviously improve the returns on Scenario A, they would not be necessary to justify a positive decision. Lower LNG prices, however, become relevant when assessing the prospects for Scenarios B, C, and D. All three cases show much improved returns at lower LNG prices, when assessed on an incremental basis vis-a-vis Scenario A. With lower LNG prices (Scenario III), Scenario C could actually be justified with a lower additional demand from high-value power units than under our base-case assumptions (about 400 KW instead of 800 MW). Note, however, that for Scenarios B, C and D, these conclusions are largely dependent on assumptions made on future distribution investment by the city gas companies -- assumptions which need to be confirmed through conceptual master plans as indicated in para. 3.47. - 72 - Suggested Agenda 3.47 We recommend that preparation work start for Scenario B as soon as possible, including (a) detailed feasibility studies for terminal capacity expansion (at Pyeong Taek and Incheon); (b) detailed design of a Pyeong Taek-Taejon pipeline (which could be conceived as a first phase of an eventual trunkline to the south); (c) detailed design for the strengthening of the existing pipeline system north of Pyeong Taek; and (d) conceptual master plans for gas distribution (backed up by discrete consumer surveys) for the Seoul/Incbeon area, the Pusan/Ulsan area, the Taejon area, and a typical low-density city. In parallel, further analysis of gas demand from the power/CHP sector in the south would need to be undertaken jointly by KGC, KEPCO and KDHC, with a view to better establishing the justification for further extension of the gas grid. In this context, early clarification of government policies in regard to the conversion of existing oil-fired power plants to gas will be essential. 4. INSTITUTIONAL AND POLICY ISSUES 4.1 The analysis presented in the preceding chapters suggests that there is clearly a significant role for LNG in the energy sector in Korea based solely on narrowly defined economic criteria. First, it appears that large quantities of gas consumption for power generation will be justified no longer simply in a "swing" consumption role. Rather, LNG, when coupled with combined-cycle generation technology, will emerge as a significant component of the least-cost power ganeration plan for the country. Second, it appears that, in areas served by the existing gas infrastructure, gas would be the economic choice in selected household, commercial and , industrial end-uses even without consideration of environmental factors. Moreover, environmental benefits, even though they are difficult to quantify, are probably sufficient to justify an expanded gas utilization strategy aimed at a progressive expansion of gas infrastructure to serve selected areas outside the Seoul metropolitan area. Overall, KEEI's target of some 10 million tons of LNG to be imported annually by 2010 (or 7.5X of total primary energy in that year) appears reasonable. 4.2 While the case for giving LNG a significant role as part of both a least-cost energy supply strategy and a least-cost pollution control strategy is quite compelling, there is a risk that, because of the magnitude of costs involved, government attention would be focussed on investment implementation to the detriment of policy development. There is indeed a complementary need for policy formulation to ensure that the combination of market forces with selective government intervention leads to an economically efficient LNG consumption pattern. An important conclusion emerging from the previous chapters is that gas utilization needs to be carefully charted to ensure that it leads to an efficient use of resources; this applies particularly to the goal of reducing air pollution through fuel switching. However, while the general parameters that govern the economic attractiveness of gas use in power and selected - 73 - (both in terms of location and type) household, commercial and industrial end-uses are known, much remains to be done to adequately define a gas utilization plan and an implementation strategy for Korea. This will involve resolving a number of institutional issues dealing with the questions of system planning, market analysis, pollution control options, technology availability and regulatory issues. This chapter presents a preliminary discussion of these important topics. A. Strategy Formulation and System Planning 4.3 A critical feature of the proposed gas strategy is the central role to be played by the power sector (including CHP plants both for district heating and industrial park supply). The pattern of gas-fired power units will largely dictate the structure of the main gas infrastructure (e.g., terminals and main transmission lines). At the local level, industrial (and large commercial) demand will be the main determinant of the viability of setting up a distribution grid, while the development of residential (and small commercial) markets will, in turn, depend on decisions made in regard to power generation and industry. This underscores the need to lift as soon as possible the remaining uncertainties conicerning these two critical sectors. Our recommendation (para. 3.4) that industrial market surveys be carried out before extending the existing gas infrastructure to other regions is motivated by this general assessment. (1) Power System Planning 4.4 Much progress has been done recently in defining the future role of LNG for power development. KEPCO is firming up its projections of gas utilization in the Seoul area and KGC is making plans accordingly to meet the revised demand scenario. Now that the basic premise that gas-fired combined-cycle plants would be an attractive adjunct to KEPCO's present array of plant types has been established, there is a need to rationalize and strengthen the interface between power planning and gas infrastructure planning. The long-term use of gas in power plants (including CHP plants), in the Seoul area, and more importantly outside this area, will be a critical factor in defining and justifying future gas infrastructure investments. Details, however tentative, of the pattern of Luture consumption need to be worked out (e.g., quantities, plant locations, etc.) at an early stage since they will condition such major decisions as the location and timing of future terminals and bulk transmission lines. To strengthen the interface between the various agencies involved, we recommend that the Government consider the establishment of a task force consisting of representatives of KGC, KEPCO, HOER (and possibly KDHC) with a view to improving coordination of these agencies' planning efforts. - 74 - (2) Residential, Commercial and Industrial Markets 4.5 The need to strengthen the planning capability of the city gas companies was underscored when discussing the estimates of likely future investments in gas distribution facilities. There are several ways for the Government to address this question. The choice of method will clearly affect the nature of the regulatory environment the Government would want to enforce vis-a-vis the companies; it will also impact on KGC's role in assisting the Government structure a strategy for the sector: (a)GOK could set broad objectives for the city gas companies based on its own assessment of future demand and request them to prepare medium to long-term development plans aimed at meeting these objectives. These plans would also include the companies' recommendations towards changes in policy as well as pujlic sector contribution to the financing of investments, and would be reviewed by GOK. (b)Alternatively, GOK would prepare a gas distribution master olan for the Seoul metropolitan area, as well the financial and regulatory framework that would make its implementation possible. This master plan would be used as a basis for negotiating long-term supply agreements with private utilities. As in the first alternative, these agreements would also serve as a basis for the design of large infrastructure facilities by KGC and be an input in the size and timing of future LNG import contracts. 4.6 Under either approach, GOK needs to have a reasonable knowledge of the costs involved with various alternative distribution strategies. In the second approach, the Government would assume a more direct involvement in the formulation of policies and investments. In view of the extent of externalities involved (largely due to the environment issue) which restricts the scope for purely commercial transactions, we think that this is the most reasonable approach. In this case, KGC should take the lead in commissioning the work for the preparation of the master plan. 4.7 Irrespective of the way the Government decides to deal with the city gas companies, KGC would need to undertake as early as possible specific conceptual studies for the main urban areas where it currently is, or could soon be, supplying natural gas. This would enable KGC to plan its transmission investments with sufficient confidence in its forecast of downstream developments. These studies should be undertaken in close collaboration with the ucility(ies) involved and would be instrumental in strengthening the links between KGC and the distribution companies independently of the Government's choice of a regulatory framework. - 75 - 4.8 Gas penetration of the residential market will depend largely on a institutional mechanisms that condition investment decisions in the housing sector. Given the magnitude of the investment programs to be undertaken, a lot more needs to be done to clarify government priorities in the area of urban planning inasmuch as they affect fuel choices. With a view to this objective, we recommend that the Government establish a working group on energy use in the residential sector, which would be in charge of preparing an "energy zoning plan" (initially for the Seoul metropolitan area), together with the necessary regulations. (3) Safety Codes and Standards 4.9 In parallel with the construction of the existing gas transmission and distribution system, the initial framework for a regulatory system has been developed by KGSC. This framework, which is based on a compilation of systems in application in other countries, provides for (a) safety codes, defining minimum standards for gas supply system and end-use equipment; (b) engineering standards for the design and construction of gas supply system and end-use equipment; and (c) the legislative basis for regulating the operations of public and private entities involved in the sector. 4.10 The rapid pace at which gas has been introduced in Korea has led so far to a generally straight adoption of codes and standards from the countries supplying the technology. While this was indeed the most expeditious approach in the initial phase, consideration now needs to be given to a detailed review of these codes and standards (a) to identify any lacuna in the existing system; and (b) to induce greater cost effectiveness in the design, construction and operacion of gas supply systems and end-use equipment, taking the specificity of the Korean environment into account. Streamlined codes and standards could be instrumental to hring about the reduction in the costs of supply systems and the improvemeit in equipment efficiency that are seen as critical to the successful impl,mentation of the proposed gas strategy. 4.11 The review and development of codes and standards could follow the following four-step approach: (a)identification and prioritization of issues through a risk analysis of designs and operational procedures for supply systems and end-use equipment installation and use; (b)operational and environmental research in design criteria, materials, installation techniques and operational parameters, taking into account consumer know-how and public exposure; (c)development of relevant Korean codes and standards; and (d)amendments, if required, of enforcement proceoures. - 76 - 4.12 KGSC has the expertise and experience required to carry out the above program with che assistance of KGC, selected city ges conmanies and equipment manufacturers. Additional expertise for specific purposes car, be obtained from the international gas industry. KGC should take the lead in carrying the ground work for this review, with KGSC and the Korean Standards Institute providing direction and quality control and being responsible for final submission to the Government. The successful completion of this program would provide the Korean gas industry with a strong technological base. It would need, however, to be subject to a continuous updating process to benefit from further advancements in materials and techniques. B. Environmental Quality and LNG Use 4.13 The future role of natural gas in Korea and envirornmental issues are closely intertwined. Yet, little analytical work has been done so far to define a rational environmental strategy in the context of which the gas option could be properly evaluated. While the construction of a national gas infrastructure can be justified, albeit for part of it on a marginal basis, based on narrowly defined economic criteria (i.e., ignoring potential environmental benefits), the rationale for such an ambitious gas strategy would be clearly strengthened if it was conceived in the context of a coherent environmental strategy based on an economic analysis of air pollution control options that would establish the relative advantages of gas use in specific applications. This analysis would need to examine existing fuel quality regulations, fuel switching options, as well as possible emissions controls and other (conversion efficiency regulation) policy options. The evaluation should be based on economic and other criteria including administrative feasibility. And, at least with respect to household energy consumption, it should consider equity as well as aconomic efficiency criteria. 4.14 Current regulations on fuel use are apparently based at least partially on administrative ease and on an assumption that commercial users could more easily bear the financial costs of conversion and the additional energy costs of LNG city gas as opposed to HFO than residential consumers. Yet, residential energy use is overwhelmingly the greatest source of air pollution in urban areas and a major source of other environmental concerns (coal briquettes account for much of the solid waste disposal problem). Conversion of coal users in the household sector to a cleaner fuel is apparently considered administratively an intractable problem. Yet, experience in other countries would suggest that with the appropriate technologies, financing and institutional delivery mechani-ms, large scale household fuel switching is feasible. Such fuel switching, along with other options and issues outlined below, requires analysis. 77 - Polcy Options 4.15 The range of environmental control options potentially applicable (technically feasible) for each specific pollutant of concern includes current applications in Korea as well as alternatives not currently in use but which appear to deserve consideration aU, e.g. emission relocation DJ, end-use location control M, fuel treatment (i.e., desulfurization), emission and combustion control, and fuel switching to am cleaner fuels. 4.16 The range of alternative emission control measures is discussed in Chapter 2. Reflecting GOK's concern with sulfur, FGD is a mandated control on new coal power plants, and is expected to become also mandated for other large-scale users in the industrial sector. It is unclear, LA however, whether the technical and economic tradeoffs of mandating such controls for smaller facilities have been done, compared to switching to cleaner fuels or relying on centralized CHP plants (managed by industrial utilities). 4.17 Emission control can also be achieved through tighter combustion/end-use technology standards. Thus, the efficiency standards placed on manufacturing for boilers (greater than 1 MT/hour) have been raised gradually since 1982. This has led to increases of more than lOX in the case of larger oil boilers (5 MT/hr or more). There is an urgent need, however, to introduce similar standards for gas boilers (which are not covered under the existing regulations); and to extend the manufacturing standards to smaller boilers for all fuels. 4.18 Government policies have been largely focussed on HFO users and large users of coal (power). Yet, as seen in Annex 13, per unit of energy, coal is the biggest problem, and it is a problem for more than just sulfur 38/ The focus of the Government's environmental concern is assumed to be essentially on the urban and highly industrialized environment. The approach could be different if the concern was broader geographically, dealing with the overall national environmental quality, or even the global atmospheric warming concerns. However, some environmental control options are applicable for both narrowly defined and more macro problems. I2/ This aims to minimize the point or area impact of the emission; it includes the options of increasing stack heights or physically relocating facilities and/or building new facilities (such as coal-burning power plants) away from urban areas. In Korea, in effect such controls are being utilized for electric power users. g/ This option, often implemented through changes in zoning regulations, prevents increased end-uses of particular types in specific areas. De facto use of this option, driven more by rising land values and other matters than by environmental concerns, is already taking place. - ./a - dioxide. The figures also suggest that use of diesel is not to be ignored. Hence, the following alternatives not currently in use should be examined: (a)Foster the switching of household coal users to city gas through special assistance programs. This would include a consideration of retrofit with very high efficiency household-sized boilers which minimize some of the retrofit costs (little or no venting). The examination of this alternative should incorporate the significant savings in solid waste removal that would be achieved. Alternatively, examine the feasibility of district heating systems in selected areas with high density of coal users. (b)Encourage the switching of some diesel users to LNG city gas. The end-use analysis indicates that gas and diesel oil are close from an economic standpoint. In a "least-cost" S02 limitation strategy, switching to gas would make sense if distribution costs can be contained. (c)As the focus moves from S02 to include other pollutants (in particular NOx,, diesel (and gasoline) end-use switching will become increasingly relevant. In this context, comressed natural gas (CNG) would be a relevant alternative for urban transport, particularly for market segments for which use of LPG use is not feasible. Conversion of city buses would be a first priority. We recommend that a detailed feasibility study of possible use of CNG (or directly of LNG) as a transport fuel be undertaken. Conclusions 4.19 LNG city gas is likely to be an important component of a "least cost" air pollution control strategy, but. such a strategy should be based on careful consideration of all options and all costs. Implementation of the preferred strategy can be through various direct or indirect policy mechanisms. Direct mechanisms would enforce or induce the use of a given option through regulations or standards, e.g., emission standards. Indirect mechanisms include pricing (of fuels or emissions) and other financial mechanisms, e.g., loans or subsidies. Finally, other market mechanisms, such as emission charges, marketable permits and other approaches, should be considered as a way to implement a least-cost strategy. 4.20 In assessing the merits of alternative policy options, the relative importance of different types of end-users need to be taken into account. This relative importance should reflect the number of users, current fuel use and emission loads (in relation to the end-use technology employed). Such considerations might suggest, for example, dramatically changing the 'mandated" downtown Seoul fuel switching priorities, shifting - 79 - the emphasis to users who heve low efficiencies and/or little remaining usefulness in tneir equipment. In any case, considerations of relative importance will necessarily focus the analysis on household coal users and the options available, one of which is conversion to LNG city gas. C. Market and Regulatory Issues 4.21 Implementation of the recommended gas strategy will finally require examination of a set of institutional and regulatory issues. Some of these issues are listed below: (1) End-Use Technology Supply 4.22 Given the current limited size of the gas market and the distortions between financial and economic prices, market pressures alone are unlikely to produce the needed availability of technologies with requisite end-use efficiencies -- namely those which are .conomically optimal. To adequately define and implement an effective gas utilization plan, a detailed technology suppiier review is required and this should be an important component of an implementation strategy for Korea. This review should integrate considerations of market analysis and, in turn, be Integrated with possible institutional and regulatory changes pertaining in particular to technology efficiency. Regulatory interventions such as introduction of end-use technology effiziency and other performance standards could be quite effective for a number of market segments, including gas burners for household cooking and space cooling equipment. Development of the relevant policies would probably be better managed centrally under KGC, which does not mean that KGC should take direct responsibility for all the tasks involved since research can be farmed out. In particular, the collaboration of KEMCO and CGA should be elicited. 4.23 Thtere also is a need to foster the introduction of additional end-use technologies (in particular small-scale high-efficiency technologies) into the Korean marketplace, as well as a complementary need to assist end-users to adopt these technologies. With the current state of market development, technology dissemination is insufficient to make information and transaction costs low enough for end-users and hence, to lead to the least-cost total (energy and technology) solution. Specific technologies requiring particular attention include small-scale cogeneration units (for commercial usage); absorptive cooling systems; and high-efficiency gas boilers for residential space heating. There also is a need to bring gas boilers of all sizes up to international standards (as was done earlier for oil/coal boilers). For each technology, the areas in need of attention include: (a) technology supply; (b) technology and other customer cost financing; (c) provision of technical assistance to users (both before installation and after service). This set of issues involve technology suppliers, financial institutions, consulting and other service - 80 - companies, as well as city gas companlies. We recommend that KGC take the lead in coordinating the required technology development activities. (2) Market Development 4.24 Experience in other countries has shovn that the development of a gas market is dependent on many factors, not just the relative financial price of the commodity. Market penetration, even to achieve end-uses that are financially and economically optimal, may take institutional change and regulatory actions unless the financial incentives are overwhelming. Because gas is imported at a high cost, such incentives are unlikely to be available in Korea. As seen from the end-use analysis, there will be applications that are economically attractive (,ither narrowly defined or more broadly in the context of a least-cost air pollution strategy), but financially not attractive. Market penetration of such end-uses will require regulatory and/or institutional changes (price change, technology standards implementation, technology import/lilensing, etc.). Among the -.lternatives to overcome these impediments inc'.ude selected energy commodity price changes; selected customer-cost adjustments (special loan funds and terms); complementary end-use technology standards (as indicated above); and revision of current regulations impacting the adoption of some high-efficiency end-use technology such as changing the rules regarding cogeneration review (to ensure, for example, that the comparison is not based solely on KEPCO's generetion costs but also g!.ve some consideration to additional costs and losses). 4.25 In addition, as environmental concerns increase, uses of alternative market mechanisms to bring financial prices in line with economic prices that reflect some environmental externalities, deserve consideration. More than the current command and control approaches (dictating emissior. standards and control technologies) need consideration. Approaches such as tradeable emission permits and emission charges can be used to attain the most cost effective path to particular environmental goals. Market mechanisms are beginning to appear in way other industrial countries address their environmental concerns and measures that could dramatically increase the use of such approaches are under consideration. We recommend that the Government examine these options. KOREA GAS UTILIZATION STUDY Energy Balance Forecast (in million TOE) . Nm MI LNG Aewv *gkj byjmHue PAnw. Pnmay E' Pc CiYGM FStm l h_ hI_y 12910.0 27.0 142.0 4405.0 0.0 37.0 7772.0 0.0 0.0 20765.0 3043.0 75.0 24503.0 44.3% T_eott 3201.0 63.0 313.0 0.0 0.0 0.0 0.0 0.0 0.0 9201.0 74.0 00 9275.0 16.3% Rins.ogm. 4265.0 3240.0 1045.0 0.0 0.0 11412.0 0.0 0.0 1319.0 17016.0 1435.0 1240 13575.0 33.3% PubA&MwOU 1972.0 1033.0 0.0 0.0 0.0 42.0 0.0 0.0 0.0 2014.0 367.0 0.0 2301.0 4.4% P4itdT 28374.0 217".0 2111.0 4435.0 0.0 11551.0 7772.0 0.0 1319.C 49016.0 5519.0 1"O 54734.0 100.0% a smm"c 1189.0 1169.0 0.0 0.0 1065.0 920.0 2932.0 11105.0 0.0 18210.0 O63.0 eaGU"R 91.0 2.0 51.0 30.0 36.0 0.0 00 0.0 0.0 189.0 205.0 Los 0.0 0.0 0.0 0.0 11.0 0.0 0.0 0.0 0.0 11.0 -844.0 4.0 P*hLft 20654.0 22059.0 2162.0 4533.0 2104.0 12480.0 10704.0 11105.0 1319.0 57420.0 44.0% 34.1% 3.2% 6.7% 3.1% 16.5% 15.9% 1O% 2.0% 100.0% ON Pw C4 LPG Hnu4ai L40 AntaM Bhumin HydVNue Rwiw. Pwnuy EJldIc CiWySm Fu4 ShWi b1b0M 14513.7 0517.3 101.6 4334. 0.0 69.s 9000.5 0.0 0.0 23643.7 41752 110.2 27029.1 46.2% Tuumupu 10635.7 9756.5 1070.2 0.0 0.0 0.0 0.0 0.0 0.0 10535.7 50.1 00 10915. 18.1% Rmluubu 5127.4 3787.4 1'40.0 0.0 0.0 10760.0 0.0 0.0 1179.0 17095.4 1709.0 227.0 1903Z3 31.5% PUatwo s 2016.3 2009.6 5.7 0.0 0.0 69' 0.0 0.0 0.0 2087.4 428.2 00 2513.6 4.2% ft4ToW 324051 25070A 2560.5 4634. 0.0 10927.5 9060.5 0.0 1179.0 53662 6391.3 337.2 00390.7 100.0% Sm ulmp 2303 2003.7 0.2 0.0 2472.9 314.7 36842 10916. 0.0 20892.5 7349.3 0oA#k U.3 1.2 30.1 26.0 236.9 0.0 0.0 0.0 0.0 305.2 337.2 Lasse 0.0 0.0 0.0 0.0 7.2 0.0 C.0 0.0 0.0 7.2 -958.0 00 P*n.UZ S3646.3 27075.7 2625. 4850.5 2713.0 11842.3 12744.7 10916.8 1179.0 74867.1 47.4% 37.4% 35% 6.5% 3.6% 15.8% 7.0% 14.0% 1.6% 100.3% OQ : o KOREA GAS UTILIZATION STUDY Energy Balance Forecast (in million TOE) low Oi F s 06 LPG ONm" LUG Mlva saurn HWaac Pmnmw Pe 0,mwy Elsgl Cllyw Pai Urn indum 12281.1 10366.3 .. 0 68 0.0 87. 1025A24 0.0 55A 28157.7 4850.3 33 33350. 47.0% no 1p7o550 1241.8 13418 0.0 Oh 0.0 0.0 0.0 0.0 13756 97.3 0.0 13820 19.6% Rmzwmn. 6337.0 4517.8 1610.2 0. 0.0 361.0 0.0 0.0 M16.7 17026.7 2111.2 469.4 19007.3 2.1% PubAC0rms 222.7 2220.0 0.7 0. 0.0 34.2 0.0 0.0 89.5 2353.4 491A 0.0 2852. 4.1% FbToW 3S9003.4 29517.3 3400.? 3634. 0.0 0754.7 10252.4 0.0 1642.8 61293.3 7567.1 303.0 69035 100.0% Swmn'bn 2915.3 2015.3 0.0 0.0 2320.8 1000.0 4231.0 13826.3 0.0 24294.3 8524.9 09Mok 2908.3 0.0 215. 32. SIB.? 0.0 0.0 0.0 0.0 815.0 503.0 Loa 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 957.8 0.0 FWoL 43517.0 324332 38185 6787.3 267.3 10704.7 14484.4 13826.3 1648 88402.6 40.6% 37.8% 4.2% 7.8% 3.3% 12% 16.% 16.0% 1.9% 100.0% 01 Fuel U LPo WI-" LUiG Ass WmIny HMyduc Ruww. Pnnwuy Elso Co*Ga Fbd 88w. Kiosay 20765.1 11682.3 68. 8333.0 0.0 22.5 14314.1 00 1157.7 36259.4 6352.1 1076.4 43687.9 48.2% uUapJn 21551. 19071.1 160.0 0.0 0.0 0.0 0.0 0.0 0.0 21551.9 138.7 0.0 21688.6 236% rsuicmnn. 763.5 5456.7 2431.6 0.0 0.0 61594 0.0 0.0 700.9 16810.8 3213.4 127.8 21852.0 24.1% PubAOtmw 2500.0 248.0 13.0 0.0 0.0 24.3 0.0 0.0 250.4 2774.7 663.4 0.0 3438.1 3.8% PFiTW 52707.5 33299.1 5018.4 8303.. 0 0 606.2 14314.1 0.0 2169.0 77338.5 10368.7 2304.2 eM6008 100.0% bminon 40103 4020.3 0.0 0.0 2607. 1094.0 0515.2 -15454.0 0.0 32391.1 11678.4 GMWnuf 104. 0.0 194.6 0.0 2706.4 0.0 0.0 0.0 0.0 2304.2 2J04.2 L s 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -1312.7 0.0 Pino as86Yu 43313.4 5t10.2 833.0 8517.0 9300.2 23829.3 15454.0 2109.0 113182.1 80.3% 38.3% 4.6% 7.4% 4.0% 8.2% 21.1% 13.7% 1.9% 10e.0% M M 0 II-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~V KOREA GAS UTILIZATION STUDY Energy Balance Forecast (in million TOE) 01 Fui 01 LP hswo US AMW U1 "F~ PAn. PrwIwy EbS CIO _ s-- 23 12222.7 4.550. 5J51.5 0.0 - .0.0 1319.6 .0.0 1705.5 43454.4 7U4.7 1500.1 525. 4.5% wpm1. - 27b17.6 225 *1.4 0.0 0.0 0.0 0.0 0.0 0.0 27617.6 111.4 0.0 2775.0 25.% PARIuM 5810.1 0100.9 2C. 0.0 0.0 677.4 0.0 0.0 7434 10346.6 4551.5 33244 24222 22 ftb8OUm 255W.5 2U1.4 -1TA 0.0 0.0 23.0 0.0 0.0 $41 1 3202.9 54.3 0.0 4"1.2 r7% Fd*Tod 52007.5 46962 52. 951.9 0.0 6103 16319.0 0.0 2794 0 9021.7 13465.5 4833.5 1091.0 100.0% _ _mpI 3312.S 5312.5 0.0 0.0 3400.5 1092.J 13225.4 21813.3 0.0 42047.7 15174.1 0k 30.0 0.0 30.0 0.0 43.4 0.0 0.0 0.0 0.0 4603.4 4533.5 Lou" 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -1708.3 0.0 c AbpL. 66040.3 502757 SO12.7 19 .5234.2 703.1 315450 21513.3 275.0 135t5 47.7% 8.3% 4.3% 7.1% 5.0% 57% 2L.% 15.% 2.0% 100.0% 2010 co VW ON LPG Nmnuh LNG AM" SWsi K^94= Rmwv. Ptnmy 3jgft CRySi FtU ohm klusy 7017.6 13954.5 116.0 1104.5 0.0 0.0 21824.9 0.0 3527.0 52370.1 11325.9 2141.0 6563., 45.3% Tuomu S4654.3 31255. 33663 0.0 0.0 0.0 0.0 0.0 49.0 4W03.3 357.9 0.0 35061.2 260D% ALrmj.W 10604.2 727.3 3036O. 0.0 0.0 3773.7 0.0 0.0 1233.3 15676.7 3107.0 51535 26937.3 21.4% Puvt&0tws 3151.2 311.7 31. 0.0 0.0 6.4 0.0 0.0 784.6 39412 1263.4 0.0 5204. 3.% FbUTUN 7547.3 50015.5 760015 11S56. 0.0 $779.1 21524.9 0.0 3600.0 10091.3 21057.3 7294.6 135043.1 100.0% Gmrom 19591 1969.1 0.0 0.0 6245. 500.0 25417.9 31533. 0.0 65969.1 23S90.0 o0zot 00.0 0 . 0.0 7294 0.0 0.0 0.0 0.0 7354.6 7264.6 Low" 0.0 0.0 0 Q0.0 0.0 0.0 0.0 0.0 0.0 0.0 -252.7 0.0 PrLn.N 77516.4 5795 7651.3 1156 .S 13543.2 4579.1 47242. 315335 5600.0 150015.0 43.1% 32.2% 4.3% 6.% 7.5% L5% 26.2% 17.5% 3.1% 100.0% @ 111 KOREA GAS UTILIZATION STUDY Energy Balance Forecast (in million TOE) Tad P,bmwy Unwo 06 Fwi 06 LPG N.. LNG OM Antin nM HdNIW Pao. P* nwV OI9L% 1357 290M4.0 225.0 21.0 450 2104.0 23164.0 12480.0 10704.0 11150.0 1319.0 6742.0 10 35 3 273757 262 460 2716.0 2145.0 1164. 12744.7 10315.5 1179.0 7487.1 11.0% 1330 42517.0 32433.2 301" 6O6t 26875 252.1 1014.? 14464.4 1320.3 1642.8 5t4026 7.4% 1065 S5S662. 43310.4 5210.2 3930 5517.0 33129.5 3200.2 2=823.3 15454.0 2109.0 113162.l 5.5% 2000 MM04.3 S025T 5t12.7 6U1.0 62)4.2 39451.1 7103.1 3154.0 21013.3 2764.0 138332. 4.1% 2010 77516.4 596U60 7661.3 11666S 13543.2 S16211 4579.1 47242.8 315235 5000.0 18O005.0 2.7% 11-10 3.0% 2.9% 3.% U.% .% 3.7% -4.2% 0.1% 4.2% 60% .7% T*W Fnal 5"wW 09 FimI 0N LPG "Nuh Cog An@h tSlWmnn Rsww. Elstlc CuyGas FoiI drskt% 1087 28374.0 21765L0 2111.0 4465.0 19323.0 11551.0 7772.0 1319.0 5519.0 ¶99.0 54734.0 'IO6 32465.1 25070.J 25615 45.0 136.1 10027J 000.5 1179.0 6301.3 337.2 00380.7 10.3% 10 39603.4 23517.3 3400.7 054.5 20047.1 1794.7 10252.4 1642.6 7567.1 803.0 O0363.5 7.4% 1305 52707.5 39230.1 5O1S.4 3U33 22520. U062 14314.1 21609.0 10305.7 2904.2 9006.6 5.4% 1 2000 297.8 480962 55L27 651.0 2512.0 610.3 15319.0 2704.0 13465.6 4533.5 105321.0 3.7% D 2010 7547.3 56i019. 7001.3 11666.8 25004.0 377.1 21U4.9 SOO0.0 21057.3 7294.5 1S3043.1 2.2% ,1-10 3.3% 3.3% 4.1% 2.9% 1.2% -&A% 3.3% 0.3% 5.3% I1.7% 3.4% Ib'iA E.flw On FUe on LPG NefF*u CoM Anmta SWnmh Rneww. Eetor CftyO.u Fin 0GofL% 1907 12916.0 5279.0 142.0 4435.0 7009.0 97.0 772.0 0.0 3043.0 75.0 24503.0 1366 14513.7 3517.3 161.6 4834.5 9130.0 09.5 9000.5 0.0 4175.2 110.2 27920.1 14.0% 1000 17281.1 10366. 230.0 0S4.5 10319.9 67. 10252.4 556.6 4659.3 333.6 3335O.S 9.3% 135 20765.1 11CS29 06. 5393.0 14320. 22.5 14314.1 1157.7 5352.1 1076.4 43657.1 5.5% 2000 23425.3 12722.7 60.7 3551.9 15319.0 0.0 18319.6 1709.5 7364.7 1509.1 52641.2 3.9% 2010 27017.0 13964.5 1106.6 11.5 21624.9 0.0 21524.9 3527.6 11326.9 2141.0 653.3 2.2% V11-0 2.3% 1.5% .6.% 2L.% 3.0% 3.6% 9.7% 4.3% 9.7% 3.5% Tnuwapuee h maw 0O FuNl 6 PG NbAfsl CoN Anywa SBumAn Renew. Elacuc C*tGw Foa GrowVh.% 130 1201.0 5233.0 016.0 0.0 0.0 0.0 0.0 00 74.0 0.0 927s.0 1OU 1035 075U 107.2 0.0 0.0 0.0 0.0 0.0 60.1 0.0 10015.5 17.7% 100 1375". 12413. 1341.8 0.0 0.0 0.0 0.0 0.0 97.3 0.0 136LO 12.7% 1995 21551.9 16671.1 100.8 0.0 0.0 0.0 0.0 0.0 135.7 0.0 21006.0 9.4% 2000 27617.0 25220.2 2309.4 0.0 0.0 0.0 0.0 0.0 181.4 0.0 27706.0 5.1% m m 2010 34654.3 32125.0 3003 0.0 0.0 0.0 0.0 49.0 357.9 0.0 35001.2 2.3% 11.10 47% 4.7% 4.7% 87% 4.8% _ KOREA GAS UTILIZATION STUDY Energy Balance Forecast (in million TOE) Rudu /CowunscWJEnugy cm Fl Oil LPO Non-Fut Coal AnMtn Sfumin RPnw. EUAic CityGs Fini Giown3.e 1087 4285.0 3240.0 1045.0 0.0 11412.0 11412.0 0.0 1319.0 1435.0 124.0 18575.0 1906 5127.4 3787A 1340.0 0.0 10789.0 101.0 0.0 1179.0 1709.9 227.0 10032.3 2.5% 1990 6337.0 4517.8 1019.2 0.0 9093.0 0093.0 0.0 908.7 2111.2 409.4 19t07.3 1.1% 1905 7890.5 5458.7 2431.8 0.0 6159.4 8159.4 0.0 760.9 3213.4 1827.8 21652.0 2.2% 2000 U16.1 3190.9 26252 0.0 6787.4 6787.4 0.0 743.4 4551.5 3324.4 24222.? 2.1% 2010 10604.2 7627.3 3036.9 0.0 3773.7 37 3.7 0.0 1233.6 8107.0 5153.5 26937.3 1.% 91-10 2.6% 2.7% 2.0% -4.6% -4.0% 1.1% 7.0% 12.1% 2.0% Pia.c & Oms. Enug Ci Fu ONi LPG Non-ust Coil Anilva Bumin Rwww. Emic City Ga Fini Growlh.% 1987 1972.0 1968.0 0.0 0.0 42.0 42.0 0.0 0.0 367.0 0.0 2361.0 1011 201113 2009.6 0.7 0.0 89.1 09.1 0.0 0.0 42.2 0.0 2513.0 5.0% 1 1990 2229.7 2220.0 9.7 0.0 34.2 34.2 0.0 B0.5 499.4 0.0 28528 6.% OD 1905 20.0 :237.0 i.0) 0.0 24.3 24.3 0.0 250.4 68.4 0.0 3438.1 3.6% 2000 21138. 2621.4 17.4 0.0 23.0 23.0 0.0 341.1 646.3 0.0 40512 3.3% 2010 3151.2 3119.7 31.5 0.0 5.4 5.4 0.0 784.A 1203.4 0.0 5204.6 2.5% 191-10 1.7% 1.7% 0.1% 4.% -L8* 11.5% 4.6% 3.1% GF*Wlh RO % PsW 01 Fuel 0 LPG Non-ust LNG An lh ytVNuo Rmn. P qNm 1-'00 13.0% 12.2% 18.7% 14.3% 10.5% -4.7% tQ.O% 7.4% 7.6% 8.O% 11-10 4.4% 4.5% &.0% 3.8% 11.2% 3.1% 6.1% 4.7% 5.5% 4.6% 01-10 1.6% 1.4% 2.6% 1.9% 5.1% -5.3% 4.1% 3.8% 7.2% 2.7% 91-10 3"% t9% 3.0% 2.8% 611% -4.2% 6.1% 4.2% 6.3% 3.7% 840 191-00 '01-10 *91-10 maimmy 10.8% 4.7% 2.2% 3.5% TIwm.po 14.3% 7.2% 2.3% 4.8% RhsJCnL 1.3% 2.1% 1.8% 2.0% FulACkovwO 6.2% 3.0% 2.5% 3.1% I" P"iToi O.4% 4.0% 2.2% 3.4% 0 ol- - 86 - Annex 2 Page 1 of 3 KOREA GAS UTILIZATION STUDY Petroleum Product Price Forecast Table 1: PROJECTION OF LANDED PETROLEUN PRODUCT PRICES IN KOREA .. ... .... . . ...... . .---- I .... .. . .......................... . ...... I Year ICRUDE OIL. LPG DIESEL InJustr. FUEL OIL .KEROSENE NAPliTHA I I I . OIL D.Oi B/C . I IUS $/St . U S D o l l a r I TOn . I 1 1989 I 18.5 126.0 173.8 143.9 93.5 182.9 171.4 I I 1990 I 156.0 184.0 157.5 104.0 197.0 185.7 I I 1991 I 20 194.3 194.8 172.5 115.8 210.8 201.5 I I 1992 I 201.9 201.3 176.6 119.5 217.1 207.8 I I 1993 . 209.7 208.0 180.9 123.3 223.7 214.4 I I 1994 I 22 . 218.0 214.8 185.3 127.3 230.4 221.5 I I 1995 I 222.5 221.5 190.7 132.0 236.3 226.3 I I 1996 . 227.2 228.4 196.2 137.0 242.4 231.2 I I 1997 . 232.0 235.5 201.9 142.2 248.6 236.3 I I 1998 I 25 236.8 242.9 207.8 147.5 255.0 241.4 I I 1999 I 240.3 246.8 211.2 150.5 259.1 245.5 I I 2000 . 243.9 250.8 214.7 153.6 263.3 249.8 1 2001 . 247.5 254.8 218.2 156.8 267.5 254.0 I I 2002 I 27 251.2 258.9 221.8 160.0 271.9 258.4 I I 2003 I 251.2 258.9 221.8 160.0 27i.9 258.4 I I 2004 . 251.2 258.9 221.8 160.0 271.9 258.4 I I 2005 . 251.2 258.9 221.8 160.0 271.9 258.4 I I 2006 1 27 251.2 258.9 221.8 160.0 271.9 258.4 ! I 2007 . 251.2 258.9 221.8 160.0 271.9 258.4 I I ..I. .. ........ ................ ............ I IPresent I I IValue * 1 203.5 214.5 184.4 127.1 228.0 216.8 1 t Present Value at discount rate: X 13 Exchange rate WOn /US S : 660 LHV : 11900 10250 10200 9800 10360 10550 KCat /Kg LPG Diesel IDO F.oil Kerosene Naphtha -87 - Annex 2 Page 2 of 3 Table 2: PROJECTION OF 'ECONOMIC PRICES' OF PETROLELH PRODUCTS IN KOREA __.______._ ........ -- -.------------ -------------------'''''''-''''''''''''''- ...........................................................F- I Year ICRUDE OIL. LPG DIESEL Industr. FUEL OIL .KEROSENE WAPHTNA I I I . OIL D.Olt B/C . IUS $/St U S D o l l a r / Ton . I 1989 I 18.5 343.2 221.8 190.7 136.4 . 236.1 231.2 I I 1990 I 37n 3 232.3 204.7 147.2 . 250.5 245.9 I I 1991 I 20 411.6 243.1 219.7 159.0 . 264.3 261.5 I I 1992 I 419.2 249.6 223.8 162.7 . 270.6 268.0 I I 1993 I 427.0 256.3 228.1 166.5 . 277.2 274.6 I 1 1994 1 22 435.3 263.1 232.5 170.5 . 283.9 281.7 1 I 1995 I 439.8 269.8 237.9 175.2 . 289.8 286.5 I I 1996 I 444.5 276.7 243.4 180.2 . 295.9 291.4 I I 1997 I 449.3 283.8 249.1 185.4 . 302.1 296.5 I I 1998 ! 25 454.1 291.2 255.0 190.7 . 308.5 301.6 I I 1999 I 457.6 295.1 258.3 193.7 . 312.6 305.7 I I 2000 I 461.2 299.1 261.8 196.8 . 316.8 310.0 I I 2001 I 464.8 303.1 265.3 200.0 . 321.0 314.2 I I 2002 I 27 468.5 307.2 269.0 203.2 . 325.4 318.6 I I 2003 I 468.5 307.2 269.0 203.2 . 325.A 318.6 I I 2004 I 468.5 307.2 269.0 203.2 . 325.4 318.6 1 I 2005 ! 468.5 307.2 269.0 203.2 . 325.4 318.6 I I 2006 I 27 468.5 307.2 269.0 203.2 . 325.4 318.6 I 1 2007 I 468.5 307.2 269.0 2.3.2 . 325.4 318.6 1 I . . . .. I I IPresent I I IValue * I 420.8 262.7 231.5 170.2 281.5 276.9 I * Present Value at discount rate: X 13 Exchange rate Won /US S : 660 LHV : 11900 10250 10200 9800 10360 10550 KCal /Kg LPG Diesel IDO F.oil Kerosene Naphtha IECONOMIC PRICE BUILD UP I IAssumptionc LPG DIESEL Industr. FUEL OIL .KEROSENE NAPHTHA I IUS S/Ton OIL D.Oi B/C . I ITerminal & Losses 63.1 24.2 23.1 20.3 25.2 31.9 I Ilnland transport 36.5 9.5 9.5 8.5 10.1 10.1 I IWholesale margin 117.7 14.5 14.5 14.4 18.2 18.2 I I I IT o t a l 217.3 48.3 47.2 4' ' 53.5 60.2 I IRetafl Margin 134.8 24.8 24.8 0 27 27 I -. - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - 88 - Annex 2 Page 3 of 3 Table 3: LANDED PETROLEUM PRODUCT PRICES IN KOREA - 1 9 8 9 - SINGAPORE & KOREA PETROLEUM PRODUCT PRICES CRUDE PRICE 19 $ /81 M a r c h 1 9 8 9 ........................ I I L P G PREMIUM NAPHTHA KEROSEN DIESEL I 0 0 FUEL OILI I . * I I II i FOB SING. March 19891 19.9 56.7 44.4 52.8 53.2 18.5 13.0 I I US Cts/Gal *US$18l I I I FOB SING. WON /lit I 34.7 98.7 77.3 92.0 92.6 76.8 54.0 I I FOB SING. USS/ Ton I 97.3 199.5 162.7 174.1 165.1 135.3 85.2 I I (Arab Gulf for LPG) I I I AFRA rate* I 500 154 150 151 150 148 143 1 I S 100 I 5.8 5.8 5.8 5.8 5.8 5.8 5.8 I I Freight cost l 28.54 8.79 8.56 8.62 8.56 8.45 8.16 1 I Insurance 1 0.13 0.21 0.17 0.18 0.17 0.14 0.09 1 I CIF Price US$/ Ton 126.0 208.5 171.4 182.9 173.8 143.9 93.5 I I LANDED KOREA S/T 1 126.0 208.5 171.4 182.9 173.8 143.9 93.5 1 i I I I Landed USS/MN8TU I 2.67 5 4.09 4.45 4.27 3.55 2.4 1 l Landed US S/Gcal 1 10.58 19.86 16.25 17 65 16.96 14.11 9.54 1 ILanded Won /liter 1 44.89 103.21 81.46 96.57 97.52 81.67 59.21 1 !I I ECONOMIC COST I I Losses 1 1.17 1.62 1.62 1.62 1.62 1.62 0.95 I I Inland Transpt W/l 1 13.00 5.35 5.35 5.00 5.35 5.00 5.35 I I Terminal cost W/l 1 21.26 11.81 11.81 11.81 11.81 11.81 11.81 I I Wholesale marg. W/i 1 41.98 21.5 9.64 9.64 8.14 8.14 9.1 1 I Econ. cost- Average I I Won /liter 1 122.3 143.5 109.9 124.6 124.4 108.2 86.4 I I I 1 I US $ /IMMBTU 1 7.27 6.96 5.52 5.74 5.45 4.71 3.51 1 I US S lMcal I 28.84 27.61 21.91 22.79 21.64 18.7 13.9. I I US $ /Ton I 343.2 289.9 231.2 236.1 221.8 190.7 136.4 I I EX REFINERY PRICES I I Won /lilter 1989 1 44.9 103.2 81.5 96.6 97.5 81.7 59.2 1 I I 1 I US $ /MMBTU (4) 1 2.67 5.00 4.09 4.45 4.27 3.55 2.4 1 I I I I US S /Ton 1 126.0 208.5 171.4 182.9 173.8 143.9 93.5 1 (1) Insurance % FOB 0.1 (4) Theoretical refinery price equal to (2) Losses * CIF 0.5 landed cost in Korea (3) Exchange WN $ 660 Specific gravity 0.54 0.75 0.72 0.80 0.85 0.86 0.96 Heating value Kcal/Kg 11900 10500 10550 10360 10250 10200 9800 GAS UTILIZATION STUDY Schedule of Domestic Petroleum Product Prices Governnent - Posted Domestic Oil Product .Prices =======.====== -t~- =====_ ==5 =======5sr 86. 11. 2. I Unit: i,'1Liter, r. U91 -_-_- ----- ----- ----- ---- ----- ----- - - -- ----- ---- ----- ----- ----- ---- ----- ----- ----- ----- ---- ----- ----- ----- ---- Refinery Agent ( Whole Sale ) Service Station ( Retail ) Before Tax After Margin After . largin After Tax SET VAT tt! Tax IET VAT Ttl Tax NET VAT Tti Tax VCUiLe - *SOl1fl 210.i8 210.78 42.16 252.94 463.72 21.50 2.15 23.65 487.37 35.12 3.;1 3S.63 `20.00 Re0b^r ias1i^ne o1-62 163.62 35.972 196.4 359.96 16. 62 1.66 18.28 378.2S 21 90 2.16 23.76 402. 00 * u~nade- cb$Xne 166.94 141.90 30.88 172.78 339.72 21.5C 2.15 2o.65 363.37 3j.12 3.51 38.63 402.00 - - - _ __ - ----------------- - -------- - -- - ------------ --- -------------------___________-____ - - ----- xernoxe=& 1145.20 14.5; 14. 5? 1i9.72 9.64 0. 96 10.60 170. 32 14. 25 1.43 i. 68 186.00 co 0. 4% D*atjel 131.56 11.84 14. 34 26. 18 157.74 8. 14 0. 81 8. 95 166.69 13.92 1. 39 1i. 31 182.00 I. - Diesel 12S.87 11.60 14.05 25.65 154.52 8.76 0.86 9.64 164.16 13.49 1.35 14.84 179.00 1.6x B - A 114.I8 11.42 11.42 12*.64 7.19 0.72 7.91 133.52 2. Oe 8 - A 112.30 11. 23 11.23 123.53 7. 19 0.72 7. 91 131.44 1.6x L. E.0. 93.54 9.35 9.35 102.8? 7.36 0.74 8.10 110.99 3.0 L.LF.0. 89.65; 8.99 8.99 98.84 ?.36 0.74 8.10 106 04 1.6% B - C 77. ?4 7.2 7.72 . 84.96 8.2. 0.83 9.10 94.06 4.2.,x 8 - .75.68 ,;Q 7.59 63.47 J.0O B ;C 7;.e61 7.36 7.36 80.97 7.43 0.74 8.17 89.14 Propane ;.en.Use) 1P5.43 15.60 21.06 36.66 231.69 77.0; 7 77 85.42 317.11 88.9? 8.901 97.39 41 .0O CxtY-S) I)),ID 8. 96 12. 1. 7. 06 123.12 Butane .cen.Usei 194.57 15.57 21.01 36.58 231.15 56.23 5.62 61.85 293.00 .ity-as) 06.33 8. 51 11. 48 19. 99 126.32 Solvene Jet A-.. JP- 4 Asphalt lietes : 1. 100. of special excise tax is currently Imposed am presiox and -egular gasoline. 85!; on unleaded gasoline. 9% on diesel and 8d on V 2. 16-; of value added tax Is tqually levied an all goods and strvices in Kurea. 3. 10-; VAt is also included in the aar;in for agents and service stations. 4. The prices of solvent and jet futl oil have beto liberallied since Feb. 6. 1083. 5. The price of asphalt has bten liberalized since Xov. 2. 1988. - 90 - Annex 4 KOREA GAS I'fILIZATION STUDY Coal Price Proiections FOB Tr. & In CIF CIF ----------(1989 U8MMT)- -------- (/ocal) 1989 37.02 11.16 48.19 7.65 1990 37.02 12.07 49.Ob 7.79 1991 37.02 12.36 49.38 7.84 1992 37.02 12.66 49.68 7.89 1993 37.28 12.96 50.24 7.98 1994 37.86 13.27 51.13 8.12 1995 38.45 13.70 52.15 8.28 1996 39.00 14.15 53.15 8.44 1997 39.S6 14.61 54.17 8.60 1998 40.13 15.08 55.22 8.76 1999 40.71 15.38 56.09 8.90 2000 41.30 15.68 56.97 9.04 2001 41.30 15.88 57.28 9.09 2002 41 30 16.29 57.59 9.14 2003 41.30 16.29 57.59 9.14 2004 41.30 16.29 57.59 9.14 2005 41.30 i6.29 57.59 9.14 2006 41.30 16.29 57.59 9.14 2007 41.30 16.29 57.59 9.14 m Net Present Value 38.46 13.51 51.96 8.25 (1989) Notes, Bituminous coal 11,340 Btu/lb or 6,300 Kcal/Kg 1988 date based on sEPCO's contract terms FOB projections based on IBRD date Transport costs linked to crude prices :EP8:0's Coal Price Structure '1988) (U8$/MT) FOB 35.16 Sea Freight 10.55 Insurence 0.05 CIF 45.76 Impo't Duties (1%) 0.46 Defense Taxes (2.5% 1.14 Port Charges 0.13 Inspection Fee 0.01 Unloeding 1.26 Other Cherges 0.01 Delivered Cost 48.77 - 91 - Annex 5 Page 1 of 4 KOREA GAS UTILIZATION STUDY LNG Price Forecast Scenario I (Base Case) Ratios LNG (fob) Transport LNG (cif) LNG (cif) LNG(fob) LNG(cif) LNG(cif) -------------($/mmbtu)------------- ($/Gcal) /Crude /Crude /D. Oil 1989 2.88 0.6S 3.S3 14.02 0.90 1.03 0.85 1990 3.12 0.70 3.82 15.16 0.90 1.03 0.82 1991 3.19 0.72 3.91 1S.52 0.90 1.03 0.82 1992 3.27 0.74 4.01 15.90 0.90 1.03 0.82 1993 3.35 0.75 4.10 16.28 0.90 1.03 0.82 1994 3.43 0.77 4.20 16.67 0.90 1.03 0.82 1995 3.S4 0.80 4.34 17.21 0.90 1.03 0.82 1996 3.65 0.82 4.48 17.77 0.90 1.03 0.82 1997 3.77 0.85 4.62 18.35 0.90 1.03 0.83 1998 3.90 0.88 4.77 18.94 0.90 1.03 0.83 1999 3.97 0.90 4.87 19.31 0.90 1.03 0.83 2000 4.05 0.91 4.96 19.69 0.90 1.03 0.83 2001 4.13 0.93 5.06 20.07 0.90 1.03 0.83 2002 4.21 0.95 5.16 20.46 0.90 1.03 0.84 2003 4.21 0.95 5.16 20.46 0.90 1.03 0.84 2004 4.21 0.95 5.16 20.46 0.90 1.03 0.84 2005 4.21 0.95 5.16 20.46 0.90 1.03 0.84 2006 4.21 0.95 5.16 20.46 0.90 1.03 0.84 2007 4.21 0.95 5.16 20.46 0.90 1.03 0.84 Net Present Value 3.49 0.79 4.27 16.96 Notes: LNG (fob) pegged on marker crude (base - crude x .9) ------ as under existing contract Transport costs linked to crude (base $.65 in 1989) Crude freight: US$9/MT in 1989, linked to crude oil prices. - 92 - Annex 5 Page 2 of 4 LNG PRICE PROJECTIONS Scenario II Ratios LNG (fob) Transport LNG (cif) LNG (cif) LNG(fob) LNG(cif) LNG(cif) -------------($/mmbtu)------------- ($/cal) /Crude /Crude /D. Oil 1989 2.73 0.65 3.38 13.43 0.85 0.99 0.82 1990 2.95 0.70 3.66 14.51 0.85 0.99 0.79 1991 3.03 0.72 3.75 14.86 0.85 0.99 0.79 1992 3.10 0.74 3.84 15.22 0.85 0.99 0.79 1993 3.17 0.7S 3.93 15.59 0.85 0.99 0.79 1994 3.25 0.77 4.02 15.97 0.85 0.99 0.79 1995 3.36 0.80 4.15 16.48 0.85 0.99 0.79 1996 3.46 0.82 4.29 17.02 0.85 0.99 0.79 1997 3.58 0.85 4.43 17.57 0.85 0.99 0.79 1998 3.69 0.88 4.57 18.14 0.85 0.99 0.79 1999 3.77 0.90 4-66 18.49 0.85 0.99 0.79 2000 3.84 0.91 4.75 18.85 0.85 0.9' 0.80 2001 3.91 0.93 4.84 19.22 0.85 0.99 0.80 2002 3.99 0.95 4.94 19.E9 0.85 0.99 0.80 2003 3.99 0.95 4.94 19.S9 0.85 0.99 0.80 2004 3.99 0.95 4.94 19.S9 0.85 0.99 0.80 2005 3.99 0.95 4.94 19.S9 0.85 0.99 0.80 2006 3.99 0.95 4.94 19.59 0.85 0.99 0.80 2007 3.99 0.95 4.94 19.S9 0.85 0.99 0.80 Net, Present Value 3.31 0.79 4.09 16.24 Notes: LNC (fob) pegged on marker crude (base - crude x .85) Transport costs linked to crude (base - $.65 in 1989) Crude freight: US$9/MT in 1989, linked to crude oil prices. - 93 Annex 5 Page 3 of 4 LNG PRICE PROJECTIONS ---------------------------------------------_ Scenario III Ratios LNG (fob) Trensport LNG (cif) LNG (cif) LNG(fob) LNG(cif) LNG(cif) -------------($mmbtu)------------- ($/Gcel) /Crude /Crude /D. Oil 1989 2.57 0.65 3.22 12.79 0.80 0.94 0.78 1990 2.78 0.70 3.48 13.82 0.80 0.94 0.75 1991 2.85 0.72 3.57 14.16 0.80 0.94 0.75 1992 2.92 0.74 3.65 14.50 0.80 0.94 0.75 1993 2.99 0.75 3.74 14.85 0.80 0.94 0.75 1994 3.06 0.77 3.83 15.21 0.80 0.94 0.75 i995 3.16 0.80 3.96 15.70 0.80 0.94 0.75 1996 3.26 0.82 4.08 16.21 0.80 0.94 0.75 1997 3.37 0.85 4.22 16.74 0.80 0.94 0.75 1998 3.48 0.88 4.35 17.28 0.80 0.94 0.75 1999 3.54 0.90 4.44 17.62 0.80 0.94 0.76 2000 3.61 0.91 4.53 17.96 0.80 0.94 0.76 2001 3.68 0.93 4.61 18.31 0.80 0.94 0.76 2002 3.75 0.95 4.70 18.66 0.80 0.94 0.76 2003 3.75 0.95 4.70 18.66 0.80 0.94 0.76 2004 3.75 0.95 4.70 18.66 0.80 0.94 0.76 2005 3.75 0.95 4.70 18.66 0.80 0.94 0.76 2006 3.75 0.95 4.70 18.66 0.80 0.94 0.76 2007 3.75 0.95 4.70 18.66 0.80 0.94 0.76 Net Present Value 3.11 0.79 3.90 15.47 Notes: LNG (fob) pegged on marker crude (base - crude x .8) Transport costs linked to crude (base - $.65 in 1989) Crude freight: US$9/MT in 1989, linked to crude oil prices. - 94 - Annex 5 Page 4 of 4 LNG PRICE PROJECTIONS Scenario IV Ratios LNG (fob) Transport LNG (cif) LNG (cif) LNG(fob) LNG(cif) LNG(cif) -------------($/mmbtu)------------- ($/Gcel) /Crude /Crude /D. Oil 1989 2.88 0.65 3.53 14.02 0.90 1.03 0.85 1990 3.00 0.70 3.70 14.69 0.86 1.00 0.80 1991 3.04 0.72 3.76 14.91 0.85 0.99 0.79 1992 3.08 0.74 3.81 15.13 0.84 0.98 0.78 1993 3.13 0.75 3.88 15.40 0.84 0.97 0.78 1994 3.19 0.77 3.96 1S.72 0.83 0.97 0.78 1995 3.27 0.80 4.06 16.13 0.83 0.9' 0.77 1996 3.35 0.82 4.17 16.55 0.82 0.96 0.77 1997 3.43 0.85 4.28 16.97 0.81 0.95 0.76 1998 3.51 0.88 4.39 17.41 0.81 0.95 0.76 1999 3.57 0.90 4.47 17.72 0.81 0.95 0.76 2000 3.63 0.91 4.S4 18.03 0.80 0.94 0.76 2001 3.67 0.93 4.60 18.26 0.80 0.94 0.76 2002 3.71 0.95 4.66 18.49 0.79 0.93 0.76 2003 3.71 0.95 4.66 18.49 0.79 0.93 0.76 2004 3.71 0.95 4.66 18.49 0.79 0.93 0.76 2005 3.71 0.95 4.66 18.49 0.79 0.93 0.76 2006 3.71 0.95 4.66 18.49 0.79 0.93 0.76 2007 3.71 0.95 4.66 18.49 0.79 0.93 0.76 Net Present Value 3.24 0.79 4.03 15.98 Notes: LNG (foi) linked 50% to crude oil end 50% to coal (base - crude x .9 as under existing contract) Transport costs linked to crude (base - $.65 in 1989) Crude freight: US$9/MT in 1989, linked to crude oil prices. of -- KOREA GAS UTILIZATION STUDY End-Use Analysis Residential, Commercial and Industrial Markets I. INTRODUCTION 1. This Annex presents the results of end-use analysis which examines the comparative economic (and financial) attractiveness of using natural gas as opposed to other fuels. This analysis is intended to serve multiple objectives: (a) to estimate the value (economic and financial) of gas in alternative end-uses; (b) to provide information regarding the attractiveness of gas infrastructure investments; and (c) to make inferences regarding sector organization and changes that private firms and government bodies would need to make to insure penetration of the most attractive end-use market segments. 2. Estimates of the value of gas in specific applications are an input to the estimation of overall subsector demand and to the examination of the economic attractiveness of supply infrastructure programs. There are two avenues in which these estimates are used in the overall supply-demand and infrastructure investment analysis. The estimates of gas value in specific end-uses, in particular the financial values, are used in estimating possible levels of demand. The economic value of gas is used as a measure of benefits in the cost/benefit analysis of infrastructure investments. 3. Even without resorting to an integrated investment analysis, it is possible to utilize the end-use analysis to provide information regarding the gas infrastruc- ture investment. This is done by incorporating estimates of infrastructure costs (for a defined supply infrastructure investment program) into the end-use analysis such that the economic cost of natural gas in a particular end-use can be compared to the economic costs of the end-use being met by an alternative competing fuel (and its associated end-use technology). In the end-use analysis these infrastructure costs are allocated to particular classes of end-users. The viability of the infrastructure investment can be considered from the perspective of the various end-uses in terms of whether the total gas cost for that end-use is lower than the cost of alternatives. 4. The comparative end-use analysis also allows inferences regarding which specific end-uses are most attractive from a gas utilization perspective; such inferences can be made in both economic and financial terms. Cases in which inferences in economic terms are not supported by the comparative analysis in financial terms suggest needed policy changes, including pricing or other regulatory mechanisms, to alleviate the distortion between economic and financial parameters. 5. Other inferences on the need for policy or institutional changes can also be drawn from the comparative end-use analysis. The total economic cost of meeting Page :' of 29 any particular energy end-use is the sum of the economic cost of the energy commodity at the point of importation or production and the costs associated with infrastructure capital ai,d operations to take the commodity from point of production or import to the point of energy end-use. The cost comparisons between an energy end-use met with gas or alternatively met via competing fuels must include the costs of the end-use technology (stove, boiler, etc.). The comparison must also include appropriate adjustments to reflect differing end-use efficiency, if any. For many energy end-uses, relative technology costs and efficiency are a critical part of the comparative calculus in determining whether gas is competitive. In the U.S. (and to a lesser extent other large, well developed natural gas markets) the end-use technology is very important to gas' competitive position; gas end-use technology is often lower in cost and higher in efficiency than the same technology which utilizes oil (and much lower in cost and higher in efficiency than the same technology for coal). In addition, for some end-uses (or combined end-uses such as space heating and cooling systems) a number of technology options are available for gas use but not for other fuels. In addition, other aspects of technology availability may be that some technologies are not as readily available from as great a diversity of euppliers, or the technologies are not available in sizes to match a large range of scale of end-use. 6. In Korea, the end-use technology market, at least as it pertains to gas-using technology, is not fully developed. Some gas end-use technologies are not available; others are available, but at costs and efficiencies which are less favorable to gas use than similar technologies in other, more well developed markets. The comparative end-use analysis allows estimation of the importance of technology availability, relative costs and efficiency to the economic use of gas. - The analysis also allows inferences regarding changes needed (such as the introduction of specific technologies) to allow market penetration in those end-use market segments in which gas is most economic. II. STRUCTURE OF THE COMPARATIVE END-USE 7. The comparative end-use analysis is done on an annualized basis, measured in terms of annual energy requirements (kcal/year). Capital costs are annualized using economic discount rates and equipment lifetimes; the annual costs are then allocated to the total number of kcal utilized per year and comparisons are made in terms of S/kcal.1 8. The methodology of the end-use comparative calculus includes estimating the various components that determine the economic costs of natural gas and competing fuels. The costs are then built up (summed) from production or import point to the point of end-use. Although all costs must be considered, it is useful to distinguish between costs at various points, thus differentiating between the costs born by the user and those born by the supplier. 9. In the economic calculus, some infrastructure costs are in some cases taken as zero (sunk), where the infrastructure is already in place and no additional investment is needed "at the margin" to supply a particular user. This is the case for many end-users in the Seoul area for the terminal and trunkline infrastructure, 1 This typa of comparison in terms of total cost/kcal is often referred to as a "levelized' cost comparison. Vof 29 but not for distribution in which additional investment is needed "at the margin." The financial analysis follows somewhat the same approach as the economic calculus in that capital costs of end-use equipment are annualized and the comparison is expressed in terms of $/kcal. III. END-USE COVERAGE AND DATA REQUIREMENTS 10. A series of 17 representative end-use case analyses were constructed to examine the competitive position of gas from both the national (economic) and financial perspectives (Table 1). These cases cover selected domestic, commercial, and industrial end-uses which differ in various ways and could therefore impact the comparative calculus. Among the most important considerations are: o differences in the end-use itself (e.g., cooking versus heating); o differences in the quantity of use in a specific sector/subsector for the same end-use (hotel space heating is provided for more hours than that of commercial offices); o differences in the quantity of use in a specific sector/subsector which are a function of scale (large versus small commercial offices). 11. Three general categories of information are needed for the analysis: (1) energy requirements for specific end-uses. (2) economic and financial supply costs of fuels delivered to the customer gate; including, in the case of natural gas, infrastructure costs for import, bulk transmission and distribution. (3) economic and financial costs (and lifetimes) of end-use technologies and other customer costs including, when gas is used, costs of service lines, meters/regulators and internal piping. 12. A number of sources were drawn upon, including KEEI, KEPCO, KEMCO, two city gas companies, complemented by mission estimates. The fuel price scenarios used in the analysis are presented in Annexes 2, 4 and 5. The estimates of economic costs of equipment and infrastructure are based on financial costs netting out taxes, as were the downstream (landed) components of petroleum products. It was not possible to determine an estimate of the economic (as opposed to financial) cost of electricity. Base Case Analysis 13. The existing terminal and trunk line infrastructure in the Pyeong Taek- Seoul area can supply significantly greater quantities of household, commercial, and industrial consumption with only an incremental distribution system and customer investment. Hence, it was decided that for the household, commercial, and industrial cases a base analysis would be defined as one in which the terminal, trunk and city ring line are treated as sunk costs. The results of this base case analysis are summarized below. 98 9Eage 4 of 29 List of End-Use Case Analysis 1. Cooking, Domestic Single Family 2. Cooking, Individual Apartment Unit 3. Cooking and Heating, Domestic Single Family 4. Heating, New 600 Unit Apartment Building (assumes apartments would have gas for cooking in any case) 5. Keating, Retrofit 600 Unit Apartment Building (assumes apartments would have gas for cooking in any case) 6. Comiiercial Space Heating (and Hot Water), Office of 3,300 Sq. Meters (1000 Pyong) 7. Commercial Space Heating (and Hot Water), Office of 39,600 Sq. Meters (12,000 Pyong) 8. Commercial Space Heating (and Hot Water), Hotel of 39,600 Sq. Meters (12,000 Pyong) 9. Commercial Space Heating and Cooling, Office of 26,400 Sq. Meters (8000 Pyong) 10. Commercial Space Heating and Cooling, Hotel of 26,400 Sq. Meters (8000 Pyong) 11. Cooking, Restaurant 12. Cogeneration of Electricity and Steam for Commercial Office 13. Industrial Process Heat - Textiles Industry 14. Industrial Process Heat - Metal Industry 15. Industrial Process Heat - Food Processing Industry 16. Industrial Process Heat - Electronics Industry 17. Industrial Process Heat - Glass Industry l - 99 - X 6 Page 5 of 29 IV. SUMMARY RESULTS 14. The results of the base analysis for each of the 17 household, commercial, and domestic cases are shown in the attached tables. The fuel alternatives examined include the following: two different city gas alternatives, one based on a combination of naphtha cracking and propane, the other based solely on a propane air mixture; kerosene; diesel (light fuel oil); LPG; and Bunker-C fuel oil (HFO). In some cases electricity directly enters the calculus. In general, however, not all fuels are applicable to all end-uses, and in some cases a particular fuel (or fuels) may be utilized with differing technologies to meet the same end-use. 15. In general, LNG-based city gas is economically attractive (without consideration of environmental factors) in selected household, commercial, and industrial end-uses. Among the more important characteristics determining a category which makes LNG city gas economic ares (1) The competition is against a high economic cost fuel (at the burner tip). This category will always include LPG, and city-gas based on naphtha and/or LPG; in some instances light fuel oil (diesel) also fits this category. (2) The user is willing to pay a premium based on the convenience or quality associated with the use of gas. Cooking falls in this category for most households; many industrial process applications also fall in this category. (3) LNG gas is used in combination with h:.gh efficiency end-use technologies which are readily available in other markets if not in Korea. Certain cogeneration and combined heatirng/cooling technologies fit this category. (1) Domestic Cooking, Single Family Dwellings 16. Table 1 presents the economic and financial ccJiparison of five alternatives for household cooking; the comparison is made on a "new" selection basis. In the absence of pipeline gas, LPG is the fuel of choice for domestic cooking. Compared to LPG, city gas (from LNG or manufactured gas) brings added convenience although at a significant added cost, and its penetration of urban markets over the last 5-10 years reflects the significant increase in domestic income achieved by the urban population. LPG is thus the fuel with which gas needs to be compared. Although there is still coal-based domestic cooking, this alternative is not considered for a number of reasons: on a quality and convenience basis it is not equivalent to a gas-based alternative. And, as incomes rise, cooking with coal is likely to decrease in use, particularly in urban areas. Strictly speaking kerosene and LPG are also not "equivalent' in quality and convenience to the three gas-based alternatives, although LPG, being a gas, is much closer. The issue of quality and convenience is very important as cooking is a consumptive energy use, and therefore fuel preference, and hence "willingness to pay" (and economic benefit), is strongly influenced by qualitative factors, particularly as household incomes rise. 17. While the introduction of LNG as a city gas feedstock results in a reduction in the cost of pipeline gas, city gas remains dramatically more costly, albeit more convenient, than LPG. The question is whether the consumer's preference is such that the additional costs are warranted economically. Profitable city gas operations have established that single-dwelling consumers are willing to pay for conveni"nce a price higher than LPG-equivalent. However, this (financially revealed) lower bound of the consumers' willingness-to-pay (about $49/GCal) is significantly lower that the estimate of economic costs of gas, including distribution, ($l22/GCal) (suggesting some cross-subsidy in the existing gas tariff structure). Absolutely clear-cut inferences as to the economic viability of gas use for cooking in Individual housings are thus not possible based on the available data base. Although there is a possibility that gas distribution costs are somewhat overestimated, the issue is whether domestic consumers are willing to pay for quality the full extent of economic costs of gas distribution. A detailed assessment of possible embedded subsidies (or cross subsidies) in the current tariffs would therefore be required before the Government decides to promote LNG as a cooking fuel in individual housing units more aggressively, particularly since an acceptable alternative exists in the form of LPG. One can presumably assume, however, that as incomes grow further, the consumers' willingness-to-pay will eventually cover the full extent of economic costs as they do in other countries. (2) Domestic Cooking, Individual Apartment Unit 18. In the case of an individual apartment unit (Table 2), an additional alternative would consist of LPG delivered in bulk to the apartment building and piped internally to individual apartments. This alternative would be equivalent in convenience and quality to direct access to city gas, while being probably cheaper both in economic and financial terms (despite unit costs of gas distribution for apartments being substantially lower than for single dwellings). (Note that kerosene would not represent an equivalent convenience alternative). If confirmed to be feasible, this alternative would undermine the rationale for city gas-based cooking by apartment dwellers (unless coupled with gas use for space heating as argued below). We therefore recommend that the technical feasibility of this alternative be investigated. On the other hand, if the piped LPG alternative is not feasible, then all the questions of preference and willingness to pay raised in the previous case also apply to the apartment case. (3) Cooking and Heating, Domestic Single Family 19. The case of domestic cooking and heating (single family) is shown in Table 3, which presents the economic and financial comparison of six alternatives. Again, the comparison is maae on a "new" selection basis; the retrofit case would place LNG gas in a less advantageous position. This case attempts to make the comparison between somewhat equivalent alternatives while including coal. In contrast to coal's exclusion from the cooking case analysis above, coal is included in this case because not only is it currently an important fuel for domestic heating, but given the retrofit costs it is likely to remain so without significant regulatory directives and/or special incentives. However, the coal- (boiler) based alternative, coupled with LPG cooking, is not really equivalent in convenience to the other alternatives. As in the case of domestic cooking, as incomes rise there will likely be changes particularly in urban areas; but these changes may be in the direction of increased heating rather than retrofitting to somewhat more convenient heating source/technology. - - 101 - Annex 6 Page 7 of 29 20. Comparing the use of gas (for cooking and heating) with a combination of LPG for cooking and diesel for heating underscores its lack of (economic and financial) competitiveness in the individual housing market because of high unit costs of distribution, unless the convenience element in cooking is taken into account. Diesel (heating) and LPG (cooking) are the least-cost options, and the ranking is the same for the financial calculus. On an incremental basis, however, gas use for heating is shown to be economically attractive if one assumes that gas would be used as a cooking fuel in any case. Moreover, if one applies the lower bound of the consumer's willingness-to-pay (as established by the ongoing gas tariff) as a measure of benefits derived from the use of gas for cooking, the combined utilization of gas for cooking and heating is only slightly less economically attractive than the gasldiesel alternative. on a financial basis, however, diesel remains substantially more attractive than gas (by about 102), which points to the need for a more disaggregated gas tariff structure to differentiate between cooking loads and the larger space heating loads which offer scope for substantial economies of scale in system design 2. 21. It should be noted that in financial terms coal is indistinguishable from diesel, and could as well be the minimum cost option. While in economic terms coal is less attractive than diesel; it is actually still less economic as the existing calculus underestimates the economic costs of the coal alternative. This is because financial prices of coal were used in both the economic and financial comparisons as information to estimate economic prices was unavailable, although coal is known to receive significant direct subsidies and, in addition, there has been no consideration of relative environmental costs. (4) Space Heating - Apart -nt Buildings 22. Two cases were examined to illustrate the issue of space heating in apartment buildings. In both cases, it is assumed that there will be city gas-based cooking (now or in the immediately foreseeable future). This appears to be the accepted planning practice for apartments for the city gas companies. Costs for gas connections, service lines. etc., are therefore only the incremental costs above those for cooking. However, as the analysis discussed thus far indicates, while it is clear that Korean consumers will pay a premium for gas-based cooking, the level of this willingness to pay is unclear, and even if there is a high willingness to pay, piped LPG may be a more economic solution to meeting consumer preference, particularly in less dense areas. Both cases refer to a 600 unit apartment building. The alternatives considered attempt to reflect (a) the range of relevant fuel choices; and (b) the individual versus central heating system options. The latter aspect i; important for multiple reasons. Increasingly, especially as incomes rise, households will want 'the control and convenience" of regulating their own space heating. And, at lower incomes, a family may not want the burden of 'common heating standards" if these are higher than their own. Also examination of the individual versus central system allows consideration of issues of first costs and the burden of the first cost. There are a number of institutional issues related to this question of first cost including who bears the cost and available financing means (e.g., individual apartment ownerlrenter (direct 2 Unit consump.ions are in a ratio of about 17 on an average basis; taking the seasonal variations in heating loads and the daily variations in cooking loads into account, the relevant ratio is probably about 1:3. 6 - 102 - Page 8 of 29 cash, direct but through financing, or through rental) or time payment from the gas company). These issues can be expected to impact directly on fuel and technology choices. 23. The first case (Table 4) represents a new apartment situation with four available options: central and individual LNG city gas alternatives, a diesel (light fuel oil) individual option and a central heating Bunker-C option. The Bunker-C option is least-cost under both the financial and economic rankings. But in economic terms individual gas is very close; given the estimation basis of the numbers, there is not a sufficient difference to distinguish between these two options. This suggests that at this scale and for new construction gas heating may be attractive, and given the individual convenience this would increase its attractiveness to the consumer. But the distortions between itnancial and economic prices will be a barrier to such use. In financial terms Bunker-C is much cheaper and there are all the first cost financing and related matters outlined earlier. 24. The second case (Table 5) analyzis the options for retrofitting an existing building. The options considered are continuation of central Bunker-C heating (alternatives #3a and M3b); switching the centralized Bunker-C to natural gas (12a and M2b); and switching completely to individual natural gas systems (alternative #1). The issue arises of the residual economic value of the existing equipmenit. The approach adopted here was to consider two bounding assumptions - i.e., setting this economic salvage value at either 10 or 100 percent of the value of new equipment. The 100 percent figure would be for the case in which the equipment was just about to be installed and the fuel switching option was being considered (options t2a and #3a). The lower figure of 10 percent ettempts to consider a situation in which the equipment is in place but has some residual value (options t2b and M3b). The comparison indicates that continuation of Bunker-C use is clearly the least-cost option in both econom.ic and financial terms, although as the time for equipment replacement nears, i.e., as the situation characterized by #3a approaches, gas becomes more competitive. (5) Commercial Space Heating (and Hot Water) 25. The intensity of energy use, which im,'acts on the scale of gas installations, is the most critical factor when analyzing the use of gas for commercial space heating. Two bounding cases were considered to characterize this relationship. The range of floor space considered goes from 3,300 sq. m. (1,000 pyong), which represents the lower end of commercial buildings served by Kukdong City Gas Co. downtown Seoul, up to 39,600 sq. m. (12,000 pyong). The case of combined heating/cooling facilities was considered separately. as well as that of hotels (because of their greater energy needs per unit of space). Six alternatives, all using boilers, are considered. These include, in addition to LNG city gas, the two other city gas options and diesel, Bunker-C and LPG-based boiler systems. The last is included only to provide a comprehensive comparison; it is rarely used for space heating in Korea. 26. In the first case considered (Table 6), the building size (3,300 square meters or 1000 Pyong) represents the small end of the range of commercial buildings served by the Kukdong City Gas Co. LNG city gas at a total cost of $58/GCal is clearly not competitive. Based on both financial and economic criteria, Bunker-C fuel oil ($38/Gcal) is the least-cost alternative, even though the efficiency of its boiler technology is significantly lower than that of its nearest competitor, diesel (light fuel oil). Part of the economic competitive disadvantage of LNG gas - 103 - Annex 6 Page 9 of 29 in the commercial space heating is due to scale. Smaller commercial buildings have significant distribution and customer (boiler, service connection, piping) capital costs; and at the lower gas use of smaller (as opposed to larger) buildings, these costs account for most of the total costs, as the energy commodity costs are only $17 of the total $S58/Gcal. 27. The impact of distribution and customer costs is dramatically lessened at larger scale and higher annual gas use. This is illustrated by the case depicted in Table 7 of a larger building size (39,600 square meters or 12000 Pyong), which exemplifies situations at the larger end of the range of commercial buildings served by Kukdong City Gas Co. As in the prev'ous case Bunker-C is the least cost option in both economic and financial terms. However, while in financial terms Bunker-C is much cheaper, in economic terms LNG gas l' very close. In fact, given the information base, the two estimates should be considered indistinguishable. This suggests that at larger scales where the impact of infrastructure and customer coste are lessened, natural gas may be an economic alternative for commercial space heating. But such a choice will not be made based on current financial prices. A close review of the gas/HFO alternative (taking into account possible modifications in relative boiler efficiencies is and the possible impact of differences in non-fuel operating costs of energy systems, is important to determine whether existing scale-determined, fuel-switching environmental regulations are grounded on appropriate economic rankings. 28. Hotels. Table 8 presents a third case developed to examine commercial space heating. This case is designed to examine the implications of hotel versus office building differences. The case incorporates a building of the same size (39,600 square meters or 12000 Pyong) as the larger office case presented above but with the much higher (per unit of space) energy use based on hotel rather than office heating; again, this is exemplified by usage rates experienced by companies in Korea. As in the previous cases, Bunker-C is the least-cost option in financial terms. However, while in financial terms Bunker-C is much cheaper, in economic terms LNG gas is now lower in cost. This reinforces the implications of the previous case, namely that at larger scale and/or higher usage where the impact of infrastructure and customer costs are lessened, natural gas may be an economic alternative for commercial space heating But, again, such choice will not be made based on current financial prices. (6) Restaurant Cooking 29. Table 9 presents the economic and financial cost estimates for five alternatives for a (small) restaurant. However, only the four gas alternatives are reasonably comparable based on cooking convenience, quality and lack of smell. Hen?e, kerosene is included only as an incidental reference. Among comparable alternatives, NG city gas is the least-cost option and there is no distortion between the financial and economic rankings. Consideration of larger restaurants would only increase the attractiveness of LNG city gas as the weight of the capital cost components (in total costs) would decrease as usage increases. A primary reason for the attractiveness of gas as a fuel for restaurant cooking is the fact that it is competing against other fuels that also start out with high energy commodity costs (as opposed to delivery and end-use technology costs), in particular LPG. Annex 6 - 104 - Page 10 of 29 (7) High End-Use Efficiency Options in Commercial Sector. 30. The commercial space conditioning cad-use is further examined with three additional case analyses which examine high end-use efficiency achieved through meeting jointly two energy end-uses. The first two cases which follow examine the use of gas-fired absorption technology to provide both heating and cooling. The third case examines internal combustion engine technology for the joint production of electricity and heat. Even more so than other cases reported herein, these analyses must be considered only as illustrative and indicative. Further analysis of these high efficiency options should be part of any overall gas development plan for Korea. 31. Heating/Cooling Systems. Table 10 looks at the total space conditioning (heating and cooling) requirements of a commercial office building (26,400 sq. maters or 8,000 pyong). Four alternatives are considered: in the first alternative (#l) natural gas is used for both heating and cooling (absorptive cooling); the second alternative (12) uses natural gas for heating and electricity for cooling; the third alternative (13) uses diesel gas for heating and electricity for cooling; finally, the fourth alternative uses Bunker-C and electricity. The important inference is that use of this high-efficiency technology (gas-fired absorption) makes gas quite competitive in economic terms ($52/Gcal): lower than diesel ($57/Gcai) and close to Bunker-C ($49(Gcal), whose costs are likely underestimated. But again, as in other cases, the financial rankings are different, indicating that financial pricing will, as in other cases, be a market barrier that wi]l prevent gas penetration of this market with this technology. 32. Table 11 shows the case of a hotel of 26,400 Sq. Meters (8000 Pyong). The higher energy consumption (of hotels compared to office buildings) decreases the relative impact of capital cost components and enhances the competitiveness of gas. In this case also, gas appears as more economic than diesel. And given the estimation basis, the economic costs of the gas heating and cooling option (S26/Gcal) must be considered indistinguishable from those of the very preliminary estimates (and likely low) for the Bunker-C alternative ($24/Gcal). But, in this case also, there is a distortion in the ranking based on financial prices, indicating the need for further analysis to define corrective measures. 33. Cogeneration of Electricity and Steam for Commercial Office. Cogeneration analysis can be particularly complex because of the range of technical options and operating procedures. The technologies vary in their mix of electricity, steam, and heat outputs which can be used to meet a wide variety of end-uses: lighting, shaft power, space heat, process heat, space cooling and dehumidification. Furthermore, the operating procedures can vary from thermal to power load following, and can involve power sales to the grid or only in-house use. The economics are complicated by cost factors such as grid electricity costs (peak, off-peak), grid prices for cogenerated electricity (peak, off-peak), stand-by power costs, and availability and cost of fuel (peak, off-peak). Despite these complexities, a simplified analysis is possible in order to indicate the potential attractiveness of cogeneration. 34. Tables 12 a&b present the case of a cogeneration system sized to meet the base-load thermal erergy demands of a commercial building (floor space: 26,400 sq. meters or 8,000 pyong) so that all of the electricity and heat produced is used in-house. The approach compares the total annual cost of meeting the thermal energy demand by cogeneration versus other fuels with conventional boilers. The - 105 - Page 11 of 29 cogeneration options are credited with the value of electricity produced; sensitivity analysis is performed to examine the sensitivity of the total annual cost to the value of this electricity credit. (An equivalent way to approach this issue could be to credit the cogenerated steam with the value of other steam raising technologies and calculate an inferred marginal cost of electricity. This electricity cost could then be compared with the ecotomic cost of delivered electricity from the grid.) 35. With the base case of valuing electricity at $0.10/kwh, gas-fired cogeneration is the least-cost option. The next least-cost options are a natural gas-fired boiler and then a bunker C-fired boiler. Diesel cogeneration is more attractive than a diesel boiler, but it ig more costly than these other options. The cogeneration option is sensitive to the value of the electricity credit which constitutes more than one-half of the total annual costs of cogeneration. In comparison to the boiler-only option, the marginal cost of cogenerated electricity is about $0.07/kwh in the case of natural gas. At electricity credits below this marginal cost, cogeneration becomes unattractive. Note that the divergence between economic and financial prices changes the ranking of attractive options, with diesel cogeneration being the least-cost option. (8) Industrial Sector 36. Gas can only compete effectively in the industrial sector in applications where its quality or other characteristics are of relevance to its end-use such as in a number of direct heat and drying processes where gas enjoys a clear albeit difficult-to-quantify technical advantage (due to its clean combustion and better flame quality because of its paucity of impurities, easy heat control, and other factors). Industrial utilization is characterized by high unit consumption. Five separate cases of direct heat applications were examined to allow for a sufficient range of parameters for gas utilization and conversion (retrofit) costs, covering the textiles industry, metal industry, food processing industry, electronics industry and glass industry (Tables 13-17). All are retrofit cases and in all cases the assumed substitution is either LPG or diesel or some mixture. To reflect the salvage value of equipment in place, a 10 percent salvage value (retrofit) case and a 100 percent value (new/whole replacement) case are used for bounding characterizations of the conversion costs involved. Since all of the industry cases are ones of relatively high energy use, it is assumed that petroleum products can be obtained directly from the refiners (avoiding the wholesaler costs) at the ex-refining price plus inland transport costs. In subsequent analyses this assumption may warrant further investigation and analysis. 37. The alternatives considered include, in addition to LNG city gas, the two other city gas alternatives, diesel (13 and 14) and LPG (t5 and 16). In the case of diesel and LPG, there are two alternatives reflecting differing assumptions regarding equipment salvage value/economic life. 38. The economic comparison shows that, despite a wide range of unit consumption (from 15 to 650 thousand cubic meters per month) gas is in all cases the least-cost choice even when the salvage value of equipment is low. However, there are distortions from economic ranking based on financial costs. This supports the view that, to compete in the industrial fuel market, the city gas companies have to be willing to sell at substantial discounts. 6 - 106 - Page 12 of 29 TABLE 1 SECTOR: DOMESTIC COOKING (Single Family Dwelling) ------------------------------------------------------------__---------- #i #2 #8 94 #5 N. Gas LPG Keroseno C. Goo C. 0*o2 LPG/Nsp. (prop) unit m^3 kg liter a's m'S keel/unit LliV 11,000 11,000 8,800 11,000 1,000 end-use efficIency (1) 70 70 46 70 70 Ocai/y- (1lo' kcel/yr) 1.98 1.96 8.08 1.98 1.96 ECON. Build Up */Goal CIF/Production 16.96 17.10 22.00 19.26 17.10 Terminel/Refining 5.96 2.45 18.96 12.48 Transmiusion/Wholoeaio 14.60 2.74 8.88 8.46 Distribution/Retail 104.93 12.78 2.80 104.98 104.98 SUBTOTAL Cons. Gate 121.89 60.44 29.79 146.61 187.96 Applilenc/Equip. S/Ocal 16.58 18.64 4.68 16.68 16.58 K cost 187.74 154.82 80.30 187.74 187.74 KIlf- 8 8 8 8 8 InhOut Pipe etc. 3/ocal 65.82 68.82 68.82 K cost 692.98 692.98 692.96 K life 20 20 20 SUBTOTAL Customer 69.91 18.64 4.56 89.91 69.91 ECONOMIC COMPARISON TOTAL I/Gcoal 191.79 69.08 84.86 216.42 207.87 TOTAL S/yr 879.75 186.78 105.80 428.61 411.68 COMPETING FUEL VRS N. GAS - 8REAKEVEN ECON. COSTS S/Genl System Investment 52.12 86.47 199.46 190.91 Invest. To Cons. Gate -17.79 -88.48 129.55 121.00 Invest. To City Gote -122.71 -188.86 24.63 16.08 Netback Value at Consumer Gate -0.88 -16.47 140.61 187.96 N. Gas LPG Kerosene C. Gost C. Gas2 FINANCIAL COMPARISON Consumer OGte (S/Goal) 45.19 69.60 88.86 46.19 48.68 Appliance/Equip. S/Gcal 14.62 16.48 4.48 14.62 14.62 K cost 161.52 170.80 88.a8 161.62 161.62 K lfe 8 8 8 8 8 InsOut Pipc sto. 8/Goal 87.41 87.41 87.41 K cost 762.27 762.27 762.27 K l.fo 20 20 20 TOTAL */Ocol 97.28 76.08 88.84 97.23 100.69 TOTAL S/yr 192.61 160.64 118.10 192.61 199.17 ---------------------------------------------------------------__------- 6 Page 13 of 29 - 107 - TABLE 2 SECTOR: DOMESTIC COOKING (Individual Apartment Unit) -------------------------------------------------------------__--------------__-- #1 #2 P t4 #5 #6 Conventional Piped ------- ------- ------- ------- --------- LPG N. Gas C. ceos LPG Kerosene C. o2 -------- LPG/"ap. (propane) unit m'8 m^3 kg liter m"s kg kcal/unit 1HV 11,000 11,000 11,000 8,800 16,000 11,000 and eff. () 80 so 80 4E 80 80 Ocal/yr (10^8 kcel/yr) 1.98 1.98 1.08 8.62 1.98 1.98 ECON. Build Up 8/Ocal CIF/Production 16.69 19.26 17.10 22.00 17.10 17.10 Terminal/Refining 18.96 5.98 2.46 12.48 6.96 Transmission/Wholesale 8.s8 14.60 2.74 8.46 14.60 Distribution/Retail 29.24 29.24 12.78 2.60 29.24 SUBTOTAL Cons. Gate 46.20 70.88 50.44 29.79 62.26 87.66 Appliance/Equip. S/Oal 16.64 16.64 18.69 8.99 16.64 18.69 K cost 188.18 188.18 165.26 80.80 188.18 155.26 K life 8.00 8.00 8.00 8.00 8.00 8.00 InaOut Pipe etc. S/oal 87.42 87.42 87.42 12.72 K cost 486.86 486.u8 489.86 165.29 K life 20 20 20 20 SUBTOTAL Customer 54.06 54.06 18.89 8.99 54.06 81.41 ECONOMIC TOTAL S/Gaol 100.26 124.99 69.18 88.78 116.84 69.07 TOTAL S/yr 198.62 247.27 138.68 118.91 280.85 186.78 COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS S/Gcal System Investment 107.98 62.17 48.09 99.88 52.11 Invest. To Cons. Gate 58.87 -1.89 -10.97 46.82 -1.96 Invwst. To City Gate 24.88 -81.18 -40.21 16.08 -81.19 Notback Value at Consumer Gate 70.98 16.07 6.99 82.28 15.01 Conventionol Piped ------------------------------------------ LPG N. Gas C. uasi LPG Kerosene C. 0*2 --------- FINANCIAL COMPARISON Consumer Gate (S/Oal) 45.19 45.19 57.16 88.86 48.56 57.16 Appliance/Equip. S/Gcal 14.87 14.67 16.48 8.92 14.67 16.48 K cost 162.00 162.00 170.79 88.28 162 170.79 K life 8.00 8.00 8.00 8.00 8 6.00 InlOut Pipe etc. S/Goal 28.26 26.26 26.28 8.92 K cost 656.00 585.00 586.00 181.82 K life 20 20 20 20.00 FINANCIAL TOTAL S/GOal 86.12 86.12 78.64 87.78 89.48 82.68 TOTAL S/yr 170.61 170.61 145.81 188.00 177.17 168.48 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- - --- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --- - 108- Annex 6 Page 14 of 29 TABLE J SECTOR: DOMESTIC COOKING AND HEATING (single family du llinp) -------------._--------------_-------------------------------__--------_-----__---------------_--_------------ #1 92 #S #4 P p - - -- - -- - -- -- -- -- -- -- -- -- --- -- -- --- -- -- -- -- -- -- -- -- --- -- -- -- -- -- -- -- --- Not. LPGcook3diloslhoot LPOcookceoalhoet NOcooldeselbhat Go* C. auol LPG Di-gel C. Ga82 LPG Coal B. N. 0ae Diesel LPG/Nap. (propane) (bolier) unit N'8 0^8 kg lOter a's kg kg u'S liter kcal/unit UHV 11,o00 11o000 11,000 o ,720 15,000 11,000 4,167 11,000 0,720 end-UFA effic. (N) cooking 70 70 70 70 70 70 end-ua; offic. (3) heating es es 0o es 45 oal/yr cooking 1.93 1.03 1.93 1.96 1.93 1.93 Goal/yr beating 14.08 14.03 14.61 14.0* 26.97 14.61 Gol/yr TOTAL 16.06 16.06 1.98 14.61 16.06 1.93 25.97 1.96 14.61 ECON. Build Up /Oacel CIF/Production 16.96 19.25 17.10 20.90 17.10 17.10 16.98 20.90 Terminal/Rofining 16.96 5.96 2.34 12.46 5.90 2.t4 Tranamisalon/Whoy I-ele 8.86 14.60 2.84 8.46 14.60 2.84 Distribution/Retail 12.94 12.94 12.78 12.94 12.76 104.9J SUBTOTAL Cuut. Gats 29.90 54.52 50.44 26.66 45.93 50.44 19.70 121.69 25.69 ANNUAL EQUIP. COSTS 3/yr Cooking appliances 8/yr 82.64 82.64 86.91 82.64 86.91 82.64 X coat 187.74 187.74 164.62 187.74 154.62 187.74 K lfe 8 8 6 8 6 a Hosting appliances 9/yr 152.66 152.69 165.86 152.63 131.89 165.86 K cost 626.45 626.45 626.45 626.46 454.55 626.45 K lfe 1s 1S 10 1S 6 10 IniCut Pipe *te. */yr 186.61 18.61 186.61 105.56 K coat 896.69 696.69 696.69 692.96 K lfe 20 20 20 20 SUBTOTAL Cone. Equip 8/yr 822.18 82218 86.91 165.86 822.18 86.91 181.69 186.41 165.86 ECONOMIC COMPARISON TOTAL 5/Ocal 49.96 74.56 69.03 86.27 66.08 69.03 24.76 191.79 66.27 TOTAL J/yr 602.26 1197.76 695.61 LPGDO 1060.51 760.27 <-LPu ool 986.76 NOAdleoal COMPETING FUEL VRS NAT. GAS - iREAKEVEN ECON. COSTS */Ocal C.Gaol LPuaDO C..aa2 LPOaCooIB NG&dlesel dioel System Inveotmant 57.62 26.87 49.07 81.62 a/ 22.74 Invest. To Cons. Gate 87.56 6.81 29.02 11.57 9.70 Invest. To City Gate 24.68 -6.68 16.03 -1.87 9.70 Netback Voluo at Consumer Gate 54.52 28.27 45.96 26.58 26.66 -------------------------------------------------------------------------------------------------------------- 91 92 #4 #4 #P to FINANCIAL COiPARISON N. Gas C. Ganl LPG 6Oleeel C.Gaa2 LPO A Coal N. Gas Wlesel LPG/Nap. Unit Costs S/Oval (Cooking) 45.19 45.19 67.16 46.6e 57.16 46.19 Unit Costa S/Ocal (Heating) 38.52 88.52 82.28 46.50 19.7 82.28 ANNUAL EQUIP. COSTS 6/yr Cooking appliances 3/yr 28.94 28.94 82.58 82.58 82.58 26.94 K coat 151.52 161.52 170.80 170.80 170.80 151.52 K life 8 6 8 8 6 8 Heating appilancea 6/yr 120.68 120.66 159.86 120.68 121.68 169.98 K cost 909.09 909.09 909.09 909.09 600.00 909.09 K lilfe 1 1S 10 1S 6 10 InBOut Pipe etc. 8/yr 150.28 160.28 150.26 116.14 K cost 966.86 986.J8 996.80 762.27 K life 20 20 20 20 SUBTOTAL Cons. Equip S/yr 800.10 800.10 82.58 159.66 808.69 82.68 121.68 145.03 119.09 TOTAL 6/yr 981.91 981.91 776.44 LPUOO 1,051.87 779.00 LPG&CoolB 965.28 NGAdleal -------------------------------------------------------------__--------------__-----------------_------------- - 109 - Page 15 of 29 TABLE 4 SECTOR: SPACE HEATING - APARTMENT (New 800 Unit Apartment Building) (assums gas Is used for cooking In any case) #1 #2 #8 t4 N. Gas N. Gas Diesel Bunk. C Indlv. Central Indiv. Central heating heating heating heoting unit m^B m^8 liter liter koal/unit LHV 11,000 11,000 6,720 9,400 end-use efficiency (#) Oa 8s 80 80 caol/yr (10^6 kcal/yr) 9.a4 9.84 9.89 9.89 ECON. Build Up I/Gcal CIF/P.oduction 16.90 16.96 20.9 18.00 Terminal/Refining 2.84 2.06 Transmission/Whoesale 2.84 2.20 letribution/Retail 6.20 6.20 SUBTOTAL Cons. Gate 28.16 28.16 26.56 17.26 Appliance/Equip. S/GOal 12.27 14.56 18.28 16.19 K cost 819.88 786.60 578.56 699.28 K life 1s 15 10 10 InhOut Pipe etc. S/oal 0.42 1.12 K cost 26.08 69.44 K life 20 20 SUBTOTAL Customer 12.89 15.69 16.19 ECONOMIC TOTAL S/GOcal 86.85 88.85 88.66 88.45 TOTAL 8/yr 884.71 882.74 876.42 824.01 COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS 5/Goal System Investment 23.86 17.76 Invost. To Cust. Gate 10.67 6.06 Invost. To City Gate 4.47 -1.15 Netback at Consumer GOte (vs #1) 27.68 22.02 N. Gas N. Gas Olisel Bunk. C FINANCIAL COMPARISON Indiv. Central Indiv. Central Cons. Cato S/Geal a8.62 88.62 28.97 15.48 Appliance/Equip. 9.71 11.64 11.46 18.97 K cost 681.82 810.28 680.91 769.16 K life 16 15 10 10 InhOut Pipe etc. 0.80 0.78 K cost 28.64 75.29 K life 20 20 TOTAL S/Gcal 48.68 50.84 40.48 29.45 TOTAL 8/yr 465.05 474.66 891.57 285.26 _ _ _ I -- --_-- --- -- --- --- -- --- -- --- -- --- -- A 6 - 110 - Page 16 of 29 TABLE 6 SECTOR: SPACE HEATING - APARTMENT (Existing 600 Unit Apartment Building) (Assumes gea- would be used for cooking In any ease) -------------------------------------------------------------------__------ ------ rtrofit cases------ #1 #2& *2b #8a #b BC to BC to SC to N. Gas N. OGe N. C.e Bunk. C Bunk. C Indiv. Central Central Central Central unit M's a m8^ liter liter kcel/unit LUV 11,000 lL,OOe 11,000 9,400 9,400 end-use efficlency (X) 88 e8 88 80 bwO Ocal/yr (10^6 kcal/yr) 9.84 9.84 9.84 9.69 9.89 ECON. Build Up S/Oeal CIF/Production 16.96 16.96 16.96 18.00 18.00 Terminal/Refining 2.06 2.06 TransmissIon/Wholesale 2.20 2.20 Dlstrlbution/Retall 6.20 6.20 6.20 SUBTOTAL Cons. Gate 28.16 28.16 28.16 17.26 17.26 ApplIance/Equip. 5/Ocal 16.76 16.36 2.91 16.19 1.62 K cost 797.62 776.80 146.99 699.28 69.92 K life 15 15 16 10 10 In&Out Pipe etc. 3/GOal 0.42 1.48 1.48 K cost 26.03 87.98 87.98 K life 20 20 20 SUBTOTAL Customer 16.21 16.80 4.84 l6.19 1.62 ECONOMIC TOTAL 3/Ocal 89.87 89.96 27.60 88.45 18.88 TOTAL S/yr 867.64 878.06 26e.79 824.01 182.87 COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS S/Ocal System Investment 17.76 2.68 Invest. To Cust. aOte 1.64 -18.68 Invest. To City Gate -4.68 -19.78 Netback Volue at Consumer Gate *8a and p8b vs #i 18.50 8.88 8 vo #2o and *Sb vs #2b 17.91 16.24 N. Gas N. Gas N. OGs Bunk. C Bunk. C FINANCIAL COMPARISON Indiv. Central Centrol Central Central Cons. Gate S/Ocal 88.62 88.62 88.62 16.48 16.48 Appliance/Equip. 12.49 12.16 2.80 18.97 1.40 K cost 877.27 868.98 161.69 769.16 78.92 K life 1S 16 16 10 10 InlOut Pipe etc. 0.80 1.01 1.01 K cost 28.64 96.72 98.72 K life 20 20 20 FINANCIAL TOTAL S/Goal 61.81 61.69 41.88 29.46 16.88 TOTAL 8/yr 479.04 482.66 890.61 286.26 168.60 NOTES: Cases 2. and So assume that the salvage value of existing equipmnt Is 100t of the value of new equipment. Cases 2b and 8b assume that the salvage value of existing equipment Is only 10X of the value of new equipment. Page 17 of 29 - 111 - TABLE 6 SECTOR: COMMERCIAL - SPACE HEATING (1,000 pyong or 38,00 sq. mteros) 91 #2 #8 #4 56 9 N. Qee C. Gas Dieel LPQ Bunk. C C. G4oa LUP/Nap. (prop) unit Ma' m^8 ItTr kg liter a kccl/unlt LH 11,000 11o,000 8,720 11,000 9,400 15,000 end off (1) 88 8s 88 88 70 8s Gcal/yr (10^8 kcel/yr) 228.88 228.88 228.86 228.s8 271.86 228.8 ECON. Build Up 5/acel CIF/Production 16.96 19.25 20.90 17.10 18.00 17.10 Terminal/Refining 18.96 2.84 6.96 2.06 12.48 Transmission/Whol esale 8.88 2.84 14.60 2.20 8.46 Distribution/RetaIl 5.99 6.99 6.99 SUBTOTAL Cons. Get* 22.96 47.58 25.65 87.66 17.26 89.08 Appliance/Equip. /Ocal 20.01 20.01 24.80 20.08 20.49 20.01 K cost ('000 5) 24.79 24.79 24.79 24.81 24.79 24.79 K life 15 15 1o 1s 10 1S InlOut Pipe etc. */Gcal 16.28 16.23 15.28 K cost ('000 *) 22.96 22.96 22.95 K life 20 20 20 SUBTOTAL Customer 85.29 86.29 24.80 20.08 20.49 85.29 ECONOMIC TOTAL S/GOcal 68.24 82.87 49.88 57.69 87.75 74.32 TOTAL 8/yr 18,880 18,965 11,415 18,202 10,245 17,010 COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS S/Bcnl System Investment 65.91 82.92 40.78 27.80 67.86 Invest. To Cons. Cate 80.62 -2.87 5.44 -7.49 22.07 Invest. To City Gate 24.68 -8.87 -0.56 -18.48 16.08 Notbeck Value *t Consumer Gate 47.58 14.59 22.40 9.47 89.08 N. Gas C. Gas Diesel LPG Bunk. C C. Gas2 FINANCIAL COMPARISON Cons. Gate S/Ocal 88.62 89.62 28.97 48.68 16.48 48.44 Appliance/Equip. 15.85 15.85 20.96 26.78 17.68 15.85 K coat ('000 S) 27.27 27.27 27.27 46.06 27.27 27.27 K Ilfe 15 1s 10 1S 10 1s InlOut Pipe etc. 10.72 10.72 10.72 K cost ('000 8) 26.25 25.25 25.26 K liTf 20 20 20 FINANCIAL TOTAL S/Gcal 65.08 65.08 49.92 70.44 88.16 70.01 TOTAL S/yr 14,896 14,896 11,425 16,121 8,999 16,022 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- - --- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- - --- -- -- -- -- -- --- Page 18 of 29 - 112 - TABLE 7 SECTOR: COMMERCIAL - SPACE HEATING (12,000 pyong or a9,600 sq. meters) 91 92 98 #4 96 f8 N. Gao C. Gon Dilsel LPO Bunk. C C. Oas2 LPG/Nap. (Propane) unit M8 m',^ liter kg liter M^3 kcal/unit LHV 11,000 11,000 8,720 11,000 9 '?0 1G,000 end *ff. (X) e6 88 68 es 10 8a Ocal/yt (10^8 kcul/yr) 2,746 2,746 2,746 2,748 8,266 2,746 ECON. Build Up 3/Ocal CIF/Production 16.96 19.26 20.90 17.10 18.00 17.10 T*rminal/Refining 18.96 2.84 5.96 2.06 12.48 Transmisaion/Wholesalo 8.88 2.84 14.60 2.20 8.46 Dstrilbution/Rtnail 0.88 0.88 0.88 SUBTOTAL Cone. Gate 17.79 42.42 26.58 87.66 17.26 38.87 Appliance/Equip. */Gcnl 6.02 6.02 7.81 8.02 6.17 6.02 K co-t 69,682 89,682 89,682 89,549 89,652 69,652 K liY- 15 15 1o 15 10 15 InAOut Pipe etc. 3/Oal 4.24 4.24 4.24 K cost 76,446 76,446 76,446 K life 20 20 20 SUBTOTAL Customer 10.26 10.26 7.31 6.02 6.17 10.26 ECONOMIC TOTAL 3/Ocal 26.06 52.66 82.89 48.66 28.48 44.14 TOTAL 8/yr 77,049 144,678 90,880 119,966 76,284 121,209 COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS 8/Gcel System Inveetment 85.72 16.98 26.72 10.82 27.18 Invest. To Cons. Ost. 26.48 5.67 16.46 0.55 16.91 Invest. To City Gate 24.68 4.64 16.68 -0.28 16.08 Netback Value at Consumer Gate 42.42 22.68 a8.42 17.61 88.87 N. Gao C. 0s. Diesel LPu Bunk. C C. Oaa2 FINANCIAL COMPARISON Cons. Gate S/Oal a8.62 88.62 28.97 48.66 15.16 87.76 Appliance/Equip. 4.77 4.77 8.81 4.77 5.82 4.77 K cost 96,486 98,4865 96,465 96,604 98,486 99,496 K lfe 1s 15 10 15 10 16 InAOut Pipe etc. 2.98 2.96 2.98 K cost 84,091 84,091 64,091 K life 20 20 20 FINANCIAL TOTAL 3/Ocal 46.26 46.26 85.27 48.45 20.48 45.62 TOTAL 3/yr 127,048 127,046 96,866 188,061 66,669 125,016 Page 19 of 29 - 113 - TABLE 8 SECTOR: HOTEL - SPACE HEATING (12,000 pyong or 89,600 *q. meters) *1 *2 *8 #4 #6 N. Gas C. Gas Diesel LPG Bunk. C C. G,s2 LPG/Nap. (propane) unit Ms m's liter kg liter ma - kcal/unit WHV 11,000 11,000 8,720 11,000 9,400 16,000 end off. (%) 88 8a 8a ea 70 8s Ocal/yr (1O'$ kcal/yr) 22,984 22,984 22,984 22,984 27,198 22,984 ECON. Build Up S/Gcal CIF/Productton 16.96 19.25 20.90 17.10 18.00 17.10 Terminal/Refining 18.96 2.84 5.96 2.06 12.46 Trensumssion/Wholessel 8.88 2.84 14.60 2.20 8.48 Distribution/Retail 0.10 0.10 0.10 SUBTOTAL Cons. Got S/Ocal 17.06 41.69 25.68 37.68 17.28 88.14 Appliance/Equip. S/Gcal 0.72 0.72 0.88 0.72 0.74 0.72 K cost 69,582 89,652 89,532 89,549 89,682 89,652 K life 1s 1s 1o 16 10 1s InkOut Pipe etc. 8/oal 0.61 0.61 0.51 K cost 76,448 76,446 76,446 K itfe 20 20 20 SUBTOTAL Customer 1.28 1.28 0.88 0.72 0.74 1.28 ECONOMIC TOTAL 8/Ocal 18.29 42.91 28.46 38.a8 18.00 84.87 TOTAL S/yr 419,428 984,192 606,725 880,226 489,429 788,201 COMPETING FUEL VRS NAT. OAS - BREAKEVEN ECON. COSTS S/cal System Investmente 25.96 9.50 21.42 4.38 17.41 Invest. To Cons. Gats 24.78 8.27 20.19 8.15 16.18 Invost. To City Gste 24.68 8.17 20.09 8.05 18.08 Netback Value *t Consumer Gate 41.69 25.28 87.15 20.1'1 8.14 N. Gas C. Gas Diesel LPG Bunk. C C. Gas2 FINANCIAL COMPARISON Cons. Gats 3/Ocal 88.52 88.62 28.97 48.68 16.16 87.78 Appliance/Equip. 0.67 O.5 0.76 0.67 0 .4 0.67 K cost 98,486 98,486 98,485 98,604 99,486 98,485 K life 1S 1s 10 15 1o 1s InSOut Pipe etc. 0.86 0.86 0.86 K cost 84,091 84,091 84,091 K litf 20 20 20 FINANCIAL TOTAL S/Gcal 89.45 89.46 29.72 44.26 15.80 38.71 TOTAL S/yr 904,681 904,681 681,597 1,014,819 429,595 887,651 ; A 6 - 114 - Page 20 of 29 TABLE 9 SECTOR: RESTAURANT COOKING (Average Consumption: 6 m8/hr) #1 92 98 54 95 N. soo C. U.. LPG Kerosene C. 0as2 Prop#Nsp (propane) unit M8 O'8 kg liter O'8 kcal/unit LU4V 11,000 11,000 11,000 8,800 16,000 end-use efficiency (X) 70 70 70 46 70 Ocal/yr (10o6 kcal/yr) 80 80 so 47 30 ECON. Build Up */GOci CIF/Production 16.96 19.25 17.10 22.00 17.10 Teruinal/Refining 16.96 5.96 2.46 12.49 Transmission/Wholesale 8.86 14.60 2.74 8.46 Distribution/R teil 15.16 15.18 12.78 2.60 15.10 SUBTOTAL Cons. Gate 82.14 56.76 50.44 29.79 48.22 Appliance/Equip. 6/Ocal 8.51 8.51 8.66 2.97 8.61 K cost 418 418 480 8oo 418 K llf- 7 7 7 8 7 InhOut Pipe etc. S/Ocal 6.74 6.74 6.74 K cost 1,881 1,881 1,881 K llfo 20 20 20 SUBTOTAL Customer 10.25 10.25 8.66 2.97 10.26 ECONOVIC TOTAL S/Ocal 42.89 67.01 54.10 82.76 69.47 TOTAL 8/yr 1,276 2,019 1,629 1,684 1,761 COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS /Gocal System Investment 60.05 87.14 84.00 41.61 Invest. To Cons. Gate 89.80 26.89 28.76 81.26 Invest. To City Gate 24.68 11.71 8.67 16.08 Netback Volue at Consumr Gate 56.76 48.85 40.71 48.22 N. OGs C. Onn1 LG Kerosene C. Qae2 FINANCIAL COMPARISON Cons. Gate S/Goel 45.19 45.19 57.16 8.806 46.56 Appliance/Equip. 8.16 8.16 8.29 2.92 8.16 K cost 455 466 478 8a0 466 K life 7 7 7 8 7 InAout Pipe etc. 4.78 4.78 4.78 K cost 1,464 1,464 1,464 K llfo 20 20 20 FINANCIAL TOTAL 8/Ocal 58.00 68.08 60.46 86.78 54.44 TOTAEl 8/yr 1,599 1,598 1,820 1,728 1,689 I 6 Page 21 of 29 - 115 - TABLE 10 SECTOR: COMMERCIAL - HEATING A COOLING (Office Space of 8,000 pyong or 26,400 sq. meters) #1 92 8 4 N. Gas N. Gas DXisel Eunk. C l&C iHl.¢C AeloecC 4&Si.C unit, M' M's liter liter keal/unit UfV 11,000 11,000 69720 9,400 end off. (MN 8e 68 80 80 Gcal/yr (10 6 kcal/yr) 2,091 1,426 4,242 2,242 10^8 kWh/yr 119 279 286 286 Capacity (kW) 170 645 645 546 ECON. Bulid Up U/Goal CIF/Production 16.96 l.96 20.90 18.00 Terminal/RefinIns 2.84 2.06 Transmission/Who sal 2.84 2.20 Distribution/Retail 1.09 1.60 SUBTOTAL Cons. Gate 18.05 18.66 26.58 17.26 Appliance/Equip. S/Goal 81.60 46.76 81.36 81.85 K cost 857,696 841,661 860,946 860,945 K life 1S 15 15 15 InhOut Pipe etc. I/Gcal 2.61 8.88 K cost 85,813 85,818 K life 20 20 SUBTOTAL Customer 84.21 60.65 81.86 81.86 ECONOMIC TOTAL 3/Ocal 62.26 69.15 6s.98 48.61 TOTAL Elec. Rev. 8/yr 24,846 67,858 6,547 6t8,647 TOTAL I/yr 188,662 166,466 196,190 177,640 COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS I/Go.l System Investment 62.65 76.87 67.96 Invest. To Cons. Gate 28.44 42.66 88.78 Invest. To City Oate 27.85 41.56 82.64 Netback Value at Consumer Gate 45.40 59.62 50.69 N. aOs C. Gas Dlesel Bunk. C FINANCIAL COMPARISON Cons. Oate 8/Ocal 88.62 88.52 28.97 16.16 Appliance/Equip. 25.02 87.02 25.81 25.81 K cost a98,4e6 897,089 897,089 897,089 K life 15 15 1S 15 InlOut Pipe etc. 1.88 2.68 K cost 89,894 89,894 K iife 20 20 FINANCIAL TOTAL 1/Ocal 66.87 78.22 64.28 40.46 TOTAL Elec. Rev. 8/yr 24,846 67,858 68,647 68,547 TOTAL 8/yr 161,082 179,410 190,267 159,806 -------------------------------------------------------------__ 6 - 116 -. Page 22 of 29 TABLE 11 SECTOR: COkMERCIAL - HEATING A COOLING (Hotel of 6,000 pyong or 20,400 sq. meters) #1 92 #8 #4 N. as* M. Gon Olos,l Bunk. C MaC H&leicC 4NA.eCC H&.iecC unit m^8 m,3 liter liter kecl/unit LNV 11,000 11,000 8,720 9,400 erd eff. (X) 88 8s 80 so Gcal/yr (10^6 ke.l/yr) 9,844 7,617 11,970 11,976 10^8 kWh/yr 659 1,812 1,844 1,844 Capacity (kW) 170 546 645 645 ECON. Build Up 3/Goal CIF/Production 16.96 16.96 20.90 18.00 Terminal/Refining 2.84 2.06 Transmission/Wholesale 2.84 2.20 01stribution/RitalI 0.28 0.80 SUBTOTAL Cons. Gate 17.19 17.26 25.56 17.26 Applionea/Equip. 3/Gcal 6.06 10.61 7.04 6.69 K cost 429,286 400,908 488,184 488,184 K life 16 15 15 15 InAut Pipe etc. I/Goal 0.66 0.72 K cost 85,818 86,818 K lilf 20 20 SUBTOTAL Customer 6.61 11.22 7.04 6.68 ECONOMIC TOTAL I/Geal 25.80 28.49 82.62 28.94 TOTAL Elec. Rev. 8/yr 68,256 170,841 174,084 174,084 TOTAL 8/yr 822,247 387,762 564,779 460,s80 COMPETING FUEL VRS NAT. GAS - BREAKEVEN E;ON. COSTS 3/Gcel Systm Invostment 22.48 40.41 29.86 Invest. To Cons. Gate 18.62 81.80 21.24 Invest. To City Gate 18.69 81.57 21.01 Netback Value at Consumer Gate 80.78 48.76 a8.20 N. Gas C. Gas Diesel Bunk. C FINANCIAL COMPARISON Cons. Gate 3/Ocal 88.62 a8.62 28.97 16.16 Appllance/Equlp. 6.86 8.82 5.69 5.69 K cost 472,168 476,447 476,447 476;447 K life 1s 15 1s 15 InlOut Pipe etc. 0.89 0.60 K cost 89,194 89,894 K life 20 20 FINANCiAL TOTAL 3/Gcal 45.28 47.84 84.65 20.86 TOTAL Else. Rev. S/yr 68,260 170,841 174,084 174,084 TOTAL 8/yr 614,081 581,406 689,084 428,769 6 Page 23 of 29 - 117 - TABLE 12(a) SECTOR: COMMERCIAL - COGENERATION OF HEAT AND ELECTRICITY Economic Analysis HMeting Only Cogenerstion N. Gon C- Ga1 L1fht Bunk-rC D-e l N. Gao 0 1 unit ma ^8 iter liter lit r *^a koal/unIt LHV 11,000 7,000 9,200 9,900 9,200 1l,000 thermal efficiency ( 85 8S go 75 54 4 cogen. *l-c ffie.(3) 26 20 Fuel Use - Ocal/yr 8,629 8,620 8,760 4,000 6,656 5,656 Cogen. MWh Prod./yr 1,680 1,680 Cogen Sizo - kW (see note) 479 479 ECONOMIC - B/Goal of fuel use CIF/Production 16.96 19.26 20.90 12.94 20.90 16.96 Terulnel/Refining 18.98 2.84 2.06 2.84 Transmiseion/Wholesale 8.89 2.84 2.20 2.84 Distribution/Retil 1.87 1.87 1.67 SUBTOTAL Fuel et Cust. Gate 18.98 48.48 25.58 17.20 25.69 18.88 End Use Equlp. - I/Ocal 1.79 1.79 2.02 2.06 16.80 16.80 IC cost - 84,247 94,247 41,096 44,521 479,884 479,834 unit K - */Meol 40 40 48 52 unit K - $/kW 1,000 1,000 K life 1S 15 15 15 15 15 08M (% of K cost) 8o 8% 8% 8x 4% 43 TOTAL - S/Ocal of fuel used 20.62 45.27 27.60 10.26 42.86 85.68 TOTAL (0008/yr) 78 160 104 77 286 19# Implicit cost of elec gon USc./kWh) 7.86 5.62 Cosgnration Elec. Credit (3/Gol) -80.28 -80.28 UnIt Cott after Cogen. Credit (6/Qcal) 12.15 5.40 TOTAL (COOOS/yr) 78 160 104 77 07 80 COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS 8/Ocol System Investment 28.86 18.24 8.47 25.42 Investment To Consumer Gate 26.28 16.10 10.88 8.62 Investment To City Gate 28.86 18.24 8.47 6.75 Notbick Value at Consumer Gate 42.19 82.06 27.29 26.58 SENSITIVITY OF TOTAL OOOS/YR TO ALTERNATIVE GRID ELECTRICITY PRICES _____________________________________________________________________________________________ ELEC HNsting Only Cogenoration PRICE - - - - - - - - - - - - - - - - - - - - - - - - - - - (oIff Pk N. Gas C. Goa L t BunkerC iesel N Gas (USe. /kh) OLId 0.06 78 16O 104 77 lal 9a 0.08 78 160 104 77 98 61 0.10 78 to6 104 77 6s so 0.12 78 160 104 77 a8 0 Note: Cogeneration equipment In sized to m"t peak thormal demand. Assumptions: Thermal demand 8,000 OOcl/yr Peak dmand: 856 Neal/hr Electricity demand 2,000 mWh/yr 6 Page 24 of 29 - 118 - TABLE 12(b) SECTOR: COMMERCIAL - COGENERATION OF HEAT AND ELECTRICITY Financial Comparison Heating Only Cogeneratlon N. a. C. 6 Ubht BunkerC diesel N. ag unit M's M'8 liter liter littr es8 keel/unit LHV 11,000 7,000 9,200 9,900 9,200 11,000 thermal end off. (3) s6x esx 0ox 76%X 54 64X cogen. else. off . ()26% 26X Fuel Us, - Ocal/yr 3,629 8,629 8,750 4,000 5,556 6,556 Cogan. MWh Prod./yr 1,680 1,680 Cogen Sizo - kW 479 479 FINANCIAL - 3/Gc I of fuel use Fuel et Cons. Gate 8t:.62 88.62 28.00 15.16 28.00 88.52 End-Use Equipment 1.29 1.29 1.48 1.48 12.88 12.88 K cost - 8 84,247 84,247 41,096 44,521 479,84 479,884 unit K - 8/Mcal 40 40 48 62 unit K - 2/kW 1000 1000 K life 15 16 16 15 15 16 OAM (X of K cost) as ax ax ax 4% 4X TOTAL - 8/Ocal of fuel used 89.81 89.81 29.48 16.64 40.88 50.86 TOTAL 0001/yr 141 141 110 67 224 298 Marginal Cost of Electricity Goneration (USc./kWh) 6.76 8.46 Cogen. Elsc. Credit (I/Oal) -80.28 -80.28 Unit Cost after Cogen. CrEdlt (3/Ocal) 10.10 20.62 TOTAL '0008/yr 141 141 110 67 S5 lS SENSITIVITY OF TOTAL '00O0/YR TO VARYINO ELEC. PRICE H eting Only Cogeneration PRICE N. Gaos C. Ga1 Litht OunkerC diesel N. Gas (USc./ke'h) Oil 0.06 141 141 110 67 128 182 0.08 141 141 110 67 90 148 0.10 141 141 110 67 6e 11s 0.12 141 141 110 67 28 8l 0.16 141 141 110 67 (28) 81 Page 25 of 29 - 119 - TABLE 18 SECTOR: INDUSTRIAL PROCESS NEAT TEXTILES INDUSTRY (Average Consumption: 16,000 m^3/mo) #1 #2 #P 4 6 p #7 N. ass C. G.s Diesel Diesl1 LPG LPG C. Gas2 LPG/Nap. (New) (retro) (New) (retro) (propane) unit m's rna l1ter liter kg kg m^a keel/unit LHV 11,000 11,000 8,720 8,720 11,000 11,000 16,000 end-usn efficiency (X) 80 80 80 80 80 80 80 Qcal/yr (10^8 kcsl/yr) 1,980 1,980 1,980 1,980 1,980 1,960 1,98 ECON. Build Up */Gcal CIF/Production 18.98 19.26 20.90 20.90 17.10 17.10 17.10 Terminal/Refining 18.98 2.84 2.84 5.96 6.96 12.48 Transmission/Wholesale 8.8s 0.98 0.98 8.46 8.48 8.46 Distribution/Retail 8.46 8.46 8.46 SUBTOTAL Cons. Gate 20.42 46.07 24.17 24.17 26.52 26.62 86.50 AppliTnce/Equip. 3/cal 1.19 1.19 1.26 0.12 1.19 0.12 1.19 K cost 11,019 11,019 11,019 1,102 11,019 1,102 11,019 K life 10 10 10 10 10 10 10 .n&Out Pipe etc. 3/ocal 0.96 0.85 0.86 K cost 11,019 11,019 11,019 K life 20 20 20 SUBTOTAL Customer 2.04 2.04 1.25 0.12 1.19 0.12 2.04 ECONOMIC TOTAL 8/Ocal 22.46 47.11 26.42 24.29 27.71 26.64 88.64 TOTAL */yr 44,477 98,276 50,826 48,101 64,864 52,789 76,815 COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS S/Cc.l System Investment 80.15 8.40 7.as i0.76 9.68 21.6 Invest. To Cons. Oate 28.11 6.42 5.29 8.71 7.04 19.64 Invest. To City Gate 24.65 2.95 1.88 5.26 4.17 16.08 Netback Value at Consumer G.te 45.07 28.88 22.25 25.67 24.80 86.60 N. Gas C. Gas Diesel Diesel LPG LPG C. Gas2 FINANCIAL COMPARISON (new) (retro) (new) (retro) Cons. Gate 6/Ocal 88.52 a8.62 27.41 27.41 29.01 ".01 87.78 Appliance/Equip. 1.02 1.02 1.08 0.11 1.02 0.10 1.02 K cost 12,121 12,121 12,121 1,212 12,121 1,212 12,121 K IfTe 10 10 10 10 10 10 10 In&Out Pipe ete. 0.69 0.69 0.59 K cost 12,121 12,121 12,121 K life 20 20 20 FINANCIAL TOTAL 3/Ocal 40.18 40.18 28.48 27.52 80.08 29.11 89.89 TOTAL 8/yr 79,456 79,456 56,400 54,482 59,465 67,640 77,989 Annex 6 Page 26 of 29 - 120 - TABLE 14 SECTOR: INDUSTRIAL PROCESS HEAT METAL INDUSTRY (Average Consumption: 50,000 m'S/Mo) #1 #2 #3 #4 #8 #6 #7 N. Oas C. aos Diesel Diesel LPO UPO C. Gae2 LPG/Nap. (New) (retro) (New) (retro) (propsno) unit M's m's liter liter kg kg u'8 keel/unit LHV 11,000 11,000 8,720 8,720 11,000 11,000 16,000 ord-uso efficioncy (1) so 80 60 so 90 90 s0 Ccat/yr (1O'e kcal/yr) 6,600 6,600 6,600 6,600 6,6oo 6,600 6,600 ECON. Build Up 8/Ocal CIF/Production 16.96 19.25 20.90 20.90 17.10 17.10 17.10 Terminal/Refninng 19.98 2.84 2.84 6.96 6.96 12.46 Transmission/Wholesale 8.88 0.98 0.93 8.46 8.46 3.46 Distribution/Retail 1.04 1.04 1.04 SUBTOTAL Cons. GCte 16.00 42.64 24.17 24.17 26.62 26.62 34.06 Appliance/Equip. 8/Ocal 0.89 0.89 0.94 0.09 0.89 0.09 0.89 K cost 27,648 27,548 27,649 2,766 27,648 2,765 27,648 K life 10 10 10 10 10 10 10 ln&Out Pipe etc. 8/Ocal 1.76 1.75 1.75 K cost 75,759 75,769 76,768 K life 20 20 20 SUBTOTAL Customer 2.64 2.64 0.94 0.09 0.89 0.09 2.64 ECONOMIC TOTAL S/Ocal 20.64 46.29 25.10 24.26 27.41 26.61 86.72 TOTAL S/yr 186,287 298,901 165,690 160,129 180,912 176,699 242,86 CuMPETING FUEL VRS NAI. GAS - BREAVEvIN ECON. COTs Suiical System Investment 28.88 8.14 7.80 10.46 9.65 19.76 Invest. To Cons. Cote 25.68 6.60 4.66 7.81 7.00 17.12 Invest. To City oate 24.65 4.48 8.62 6.77 6.96 16.09 Notback Value at Consumer Gete 42.64 22.46 21.62 24.77 28.98 84.08 N. OGs C. Gas Diesel Diesel U2O LPG C. Q0a2 -INANCIAL COMPARISON (new) (retro) (new) (retro) Cons. Gate 8/Ocal a8.62 88.52 27.41 27.41 29.01 29.01 87.78 Appliance/Equip. 0.76 0.76 0.81 0.06 0.76 0.08 0.76 K cost 80,808 80,808 80,808 8,080 80,808 8,030 80,808 K life 10 10 10 10 10 10 10 InAOut Pipe etc. 1.28 1.28 1.28 K cost 88,888 98,888 98,888 K life 20 20 20 FINANCIAL TOTAL 8/Ocal 40.51 40.51 29.22 27.49 29.77 29.09 89.77 TOTAL S/yr 267,846 287,846 198,224 181,427 196,509 191,984 282,469 i Annex 6 Page 27 of 29 - 121 - TABLE 16 SECTOR: INDUSTRIAL PROCESS HEAT FOOD PROCESSING INDUSTRY (Average Consumption: 70,000 m8/mo) 91 #2 98 94 #5 96 7 N. Oas C. Gas Diesel Diesel 1LP LP2 C. Os92 LP0/Nap. (Now) (rotro) (New) (retro) (propano) unit m^8 m'8 liter liter kg kg m'8 kcsl/unit LNV 11,000 11,000 8,720 8,720 11,000 11,000 15,000 end-use efficiency (N) 80 80 60 60 80 80 80 Gcal/yr (10^6 kcal/yr) 9,240 9,240 9,240 9,240 9,240 9,240 9,240 ECON. Build Up S/Ocal CIF/Production 16.96 19.26 20.90 20.90 17.10 17.10 11.10 Terminal/Refining 18.98 2.84 2.84 6.98 5.96 12.48 Transmission/Wholesale 8.86 0.98 0.98 8.46 8.46 8.46 Distribution/Retail 0.74 0.74 0.74 SUBTOTAL Cons. Oate 17.70 42.85 24.17 24.17 26.52 26.52 88.78 Appliance/Equip. 6/Ocal 0.60 0.80 0.64 0.08 0.80 0.08 0.80 K cnst 84,486 84,486 84,486 8,444 a4,486 8,444 84,485 K life 10 10 10 1O 10 10 10 InAut Pipe etc. 6/Ocal 1.86 1.86 1.a8 K cost 62,e46 82,645 82,645 K life 20 20 20 SUBTOTAL Customer 2.16 2.16 0.64 0.06 0.80 0.08 2.16 ECONOMIC TOTAL I/Ocal 19.86 44.51 25.00 24.26 27.82 26.60 86.94 TOTAL S/yr 168,687 411,266 281,089 224,086 262,891 246,750 882,116 COMPETING FJEL YRS MAT. GAS - BREARKEVE4 ECON. COSTS 1/ocal System Investment 27.66 6.04 7.29 10.86 9.64 16.96 Invest. To Cons. Gate 26.89 5.68 6.18 8.19 7.48 16.62 Invest. To City Gate 24.66 5.14 4.89 7.45 6.78 16.08 Netback Value at Consumer Gate 42.86 22.84 22.09 26.15 24.44 s8.76 N. Gas C. Gas Diesel Diesel 120 12G C. ¢as2 FINANCIAL COMPARISON (Now) (retro) (Now) (rotro) Cons. Gate 3/Ocal 88.52 86.52 27.41 27.41 29.01 29.01 87.76 Appliance/Equip. 0.68 0.68 0.72 0.07 0.66 0.07 0.66 K cost 87,679 87,879 87,679 8,788 87,879 8,766 87,679 K life 10 10 10 10 10 10 10 InhOut Pipe etc. o.96 0.96 0.9s K cost 90,909 90,909 90,909 K life 20 20 20 FINANCIAL TOTAL S/Gcal 40.16 40.16 26.18 27.46 29.69 29.08 89.41 TOTAL 8/yr 871,026 871,026 259,914 268,916 274,867 266,703 864,165 6 Page 28 of 29 - 122 - TABLE 16 SECTOR: INDUSTRIAL PROCESS HEAT ELECTRONICS INDUSTRY (Average Consumption: 150,000 mOa/mo) #1 #2 *8 #4 P P #7 N. Gas C. a.s Dlesel Diesel LPG LPO C. a.*2 LPO/Nap. (Wew) (retro) (New) (retro) (propane) unit m^8 a'8 liter liter kg kg e^8 keel/unit LHV 11,000 11,000 3,720 6,720 11,000 11,000 15,000 end-use efficiency (N) 80 60 60 60 80 80 s0 Gcal/yr (10^' kcal/yr) 19,600 19,600 19,600 19,600 19,800 19,600 19,600 ECON. Build Up 8/ocal CIF/Production 16.96 19.25 20.90 20.sC 17.10 17.10 17.10 Terminal/Refining 10.96 2.84 2.84 5.96 5.96 12.43 Transmission/Wholesale 3.86 0.08 0.98 2 '6 8.46 8.46 Distribution/Retail 0.85 0.85 e 85 SUBTOTAL Cons. Gate 17.81 41.95 24.17 24.17 26.52 26.52 88.89 Appliance/Equip. 6/cacl 2.16 2.16 2.27 2.27 2.16 2.16 2.16 S K cost ('000 8) 200 200 200 200 200 200 200 K llfe 10 10 10 10 10 10 10 InaOut Pipe etc. 8/Ocal 1.80 1.80 1.60 K cost ('000 6) 169 169 169 K life 20 20 20 SUBTOTAL Customer 8.47 8.47 2.27 2.27 2.16 2.16 8.47 ECONOdAIC TOTAL 1/Ocal 20.77 45.42 26.48 26.48 28.86 28.68 88.86 TOTAL S/yr 411,884 969,825 628,892 528,892 567,684 6s7,984 729,718 COiPETING FUEL VRS ;AT. GAS - BREAMEVE: ECON. COSTS Vocal System Invu-Amennt 28.46 9.47 9.47 il 72 11.72 19.19 Invest. To Cons. Gate 24.99 6.01 6.01 8.26 8.26 16.48 Invest. To City Gate 24.65 6.66 6.66 7.91 7.91 16.06 Notback Value at Consumer Gate 41.95 22.97 22.97 26.21 25.21 88.89 N. Gas C. Gas Dlesl Diesl LPG LPO C. 0as2 FINANCIAL COMPARISON (New) (retro) (New) (retro) Cons. Gate 6/ocal 88.52 88.62 27.41 27.41 29.01 29.01 87.78 Appliance/Equip. 1.84 1.64 1.96 1.96 1.84 1.84 1.84 K cost ('000 8) 220 220 220 220 220 220 220 K life 10 10 10 10 10 10 10 IniOut Pipe etc. 0.91 0.91 0.91 K cost ('000 8) 168 16e 186 K life 20 20 20 FINANCIAL TOTAL 2/Ocal 41.26 41.26 29.86 29.86 80.68 80.86 40.64 TOTAL 8/yr 617,268 617,268 561,874 681,874 610,986 610,986 802,608 __________________________________________________________________________________________ Annex 6 Page 29 of 29 - 123 - TABLE 17 SECTOR: INDUSTRIAL PROCESS HEAT OLASS INDUSTRY (Average Consumption: 660,000 m^8/mo) #1 #2 P #4 #P #P# N. Gas C. Ono Diesel Diesl ILP LPG C. G0s2 ProplNop. (New) (retro) (Now) (retro) (propane) unit m^a ms liter lIter kg kg e8 koal/unit LHV 11,000 11,000 8,720 8,720 11,000 11,000 16,000 L7 ctd-use efficiency (1) 80 80 80 60 60 s0 80 oal/yr (106 kc.l/yr) 86,800 86,800 85,800 85,800 65,s80 86,800 65,600 ECON. Bulid Up 8/Ocal CIFjProduction 16.96 19.25 20.90 20.90 17.10 17.10 17.10 Terminal/RefinIng 18.98 2.84 2.84 5.96 s.s6 12.46 Transmiseion/Wholosalo 8.38 0.98 0.98 8.40 -0.46 8.40 Distribution/Retail 0.08 0.08 0.08 SUBTOTAL Cone. Gate 17.04 41.69 24.17 24.17 28.52 28.62 &8.12 Appliance/Equip. S/Oal 5.16 6.16 5.40 0.64 5.16 0.52 5.16 K cost ('000 *) 2,066 2,066 2,066 207 2,066 207 2,066 K life 10 10 10 10 10 10 10 InlOut Pipe etc. 8/Ocal 1.66 1.66 1.66 K cost ('000 8) 987 987 987 K life 20 20 20 SUBTOTAL Customr 6.82 6.82 5.40 0.64 6.16 0.52 6.62 ECONOMIC TOTAL 8/Goal 28.66 48.61 29.57 24.71 81.66 27.0o8 9.94 TOTAL 8/yr (8'000) 2,047 4,162 2,587 2,120 2,716 2,819 8,427 COMPETING FUEL VRS NAT. AS - BREAKEVEN ECON. COSTS */Ocal Syst- Trwst 91.Z5 I.6 C .b : 4.72 10.07 22.98 Invest. To Cone. Gate 24.78 5.79 0.98 7.89 8.26 16.16 Invest. To City Gate 24.65 5.71 0.65 7.81 8.17 16.08 Netback Value at Consumer Gate 41.69 22.75 17.99 24.85 20.21 88.12 N. Ga* C. Gas Diesl Diesl LPG LPG C. 0Gs2 FINANCIAL COMPARISON (new) (retro) (new) (retro) Cons. Gato 8/oeal 88.62 88.62 27.41 27.41 29.01 29.01 87.78 AppIlance/Equip. 4.89 4.89 4.66 0.47 4.89 0.44 4.89 K cost ('000 8) 2,278 2,278 2,278 227 2,278 227 2,278 K llf- 10 10 10 10 1O 10 10 InhOut Pipe etc. 1.17 1.17 1.17 K cost ('000 8) 1,080 1,080 1,080 K llfe 20 20 20 FINANCIAL TOTAL S/oal 44.08 44.08 82.07 27.87 88.41 29.45 48.84 TOTAL 8/yr (8 000) 8,782 8,782 2,761 2,892 2,866 2,627 8,716 - 124- Annex 7 KOREA GAS UTILIZATION STUDY Summary of End-Use Analysis at 8Z Cost of Capital ($/GCal) Netback Available Average Available Alternative Value Rent at Distribution Rent at End-Use Fuel of Gas Cons. Gate Costs City Gate a/ Residential Cooking Indiv. Houses LPG 49 b/ 32 77 (45) Apartments LPG 49 32 21 10 Space Heating Indiv. Houses Diesel 38 c/ 21 13 21 Apartments HFO 22 5 5 0 Commercial Space Heating HFO 14-19 (3)-2 4-1 (8)-1 Heating&Cooling HPO&elec 51 34 1 34 Hotels Sp. Heat. HFO 20 3 (0) 3 Htg&Cool. HFO&elec. 38 21 (0) 21 R.cstaurant Cooking LPG 46 29 11 18 Sp. Heat. w/ Cogeneration HFO&elec. 30 13 1 12 Diesel 26 9 1 7 Industrial Boiler Fuel HFO 20 3 0-3 0-3 Direct Heat New Diesel 22-23 5-6 0-3 4-6 LPG 25-26 8-9 0-3 6-8 Retrofit Diesel 19-23 2-4 0-3 2-6 LPG 21-25 4-8 0-3 4-8 a/ Assuming an average price of gas of $17/GCal (cif). b/ Based on lower estimate of willingness-to-pay in city gas networks. c/ Assumes gas is used both cooking and heating. - 125 - Page .of 4 KOICA AS UTILIZATION Smo Nctback Vclue of Gas In Power Sector A. Netback Velue of Gas in Csbined Coele Plant (Compared to conventional coal-fired *tam plant) Table Al: Sluleation of OwFlied Cea6lage Cycle Float Capcity i 600 First Mr 1968 Load factor hrs/y 5i25 (66.54) Start-up yar 1992 Comsption TI/kilW 7200 (47 4) Lifetim yatrs 19 Gas CN STU/cft 1236 Start-. load 66% Monetary unit : US S Investment (mill.): 390 (1) I llnvestment I Operat.l GAS I GAS I Fixed Variable I ELECTR. I I Year I I Rate I Consumption I cost I Cost Cost IProductionl I million S I hrs/y I Bcf/y lOcf/d Imillion SI million S I GWH/y I 1 1986 1 0.00 I C I 0.00 0.00 1 0.00 1 0.00 0.00 1 0 1 1 1987 1 0.001 0 1 0.00 0.0 1 0.00 1 0.00 0.00W 0 1988 1 0.00 1 0 1 0.00 0.00 1 0.00 1 0.00 0.00 1 0 1 1 1989 ! 97.50 1 0 1 0.00 0.00 i 0.00 1 0.00 0.00 I 0 1 I 1990 1 156.00 1 0 1 0.00 0.03 I 0.00 I 0.00 0.00oo 0 o 1 1991 1 136.50 1 3845 1 13.44 36.81 1 112.60 1 7.46 0.37 1 2307 1 1 1992 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 1 1993 1 0.00 I 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 1 1994 1 0.00 I 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 1 1995 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 1 1996 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 1 1997 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 1 1998 1 0.00 I 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 I 1999 1 0.00 1 5025 1 20.36 55.78 1 170.61 1 11.31 0.56 I 3495 1 1 2000 1 0.00 1 5825 1 20.36 55.78 1 170.61 11.31 0.56 1 3495 1 1 2001 1 0.00 5 5825 1 20.36 55.78 1 170.61 11.31 0.56 1 3495 1 1 2002 1 0.00 1 5825 1 20.36 55.78 1 170.61 11.31 0.56 1 3495 1 1 2003 1 0.00 1 5825 1 20.36 55.78 1 170.F I 11.31 0.56 1 3495 1 1 2004 1 0.00 1 5825 1 20.36 55.78 1 170 1 11.31 0.56 1 3495 1 1 2005 I 0.00 1 5825 1 20.36 55.78 1 17C I I 11.31 0.56 1 3495 1 1 2006 5 0.005 5825 1 20.36 55.i8 1 l70Ajl i 11.31 0.56, 3495 I 1 2007 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 1 2008 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 1 2009 1 0.00 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1 1 2010 1 -39.00 1 5825 1 20.36 55.78 I 170.61 1 11.31 0.56 1 3495 1 ias price -treakeven gas price at 13% d.r. S/lBTU 6.8 1Discount rate I 0.00%1 8.00%1 11.00%1 13.00%1 14.00%1 16.00%1 lAverage fuel cost 1 4.88 1 4.88 1 4.88 1 4.88 1 4.88 1 4.88 1 I cts/kWh I I I I I I I lAverage O.M.R. costl 0.34 1 0.34 1 0.34 1 0.34 1 0.34 1 0.34 1 I cts/kWh I I I I I I I lAverage capital I 0.51 1 1.14 1 1.43 1 1.63 1 1.74 1 1.95 I Icost cts/kWh I I I I I I I I I I- I I- I lAverage electricityl 5.73 1 6.36 1 6.65 1 6.85 1 6.96 1 7.17 1 Icost cts/kwh I I I I I I I (1) Capital cost : 650 S/KW Main assumptions Construction schedule : Year -5 Year -4 Year -3 Year -2 Year -1 Comibined Cycle plant: 25 % 40% 35 % Coal plant: 15 % 15 % 25 % 25 % 20 % - The Combined Cycle plant is able to produce 2/3 of its nominal energy capacity during the 3rd year of construction. Lifetim 19 ars for Coeibned Cycle plant 24 Mrs for Coal plant -126 - Page !of 4 Table A2: SolmaItl*a Of COal-FIred Stasm Plast capacity KW : 686 First year : 1986 Load factor hrs/y 5095 (58.2%) Start-up year 199 Coinsumption BTU/kWh Om98 (384) Lifetime years 24 Coal LHlY BTU/kg : 2500 Start-up load 100% Monetary unit us S Investment (mill.): 754 (1) I llnvestment I Operat.1 COAL. I COAL I COAL I Fixed Variable I ELECTR. I I Year I I Rate IConsumpt.1 Price I Cost I Cost Cost IProductionl I- - - -I-- - -- - -I-- - - -I-- - ------------ I - -- -I-- - - - -- - - - -I-- - -- - I I I million S I hrsly 1000 Tons I S/Ton Imuillion SI millIion S I GWHi/y I I 1986 1 0.00 I 0 1 0.00 I 0.00 I 0.00 I 0.00 0.00 I 0 1 1 1987 1 113.10 1 0 1 0.001I 0.001I U.00I 0.00 0.001I 01i I 1988 1 113.10 1 Dl 0001I 0.00 I 0.001I 0.00 0.00 I 0 1 1 1989 1 188.50 1 0 1 0.001I 0.001I 0.00 I 0.00 0.001 0 1 1990 1 188.50 1 0 I 0.001I 0.001I 0.00 I 0.00 0.001i 0 1 1 1991 1 150.80 1 0 1 0.00 I 0.001I 0.00 I 0.00 0.001I 0 1 I 1992 I 0.00 I 5095 I 1255.4? I 51.09 1 64.14 1 34.68 5.10 1 3495 1 I 1993 I 0.00 I 5036 I 1255.47 I 51.65 1 64.84 1 34.68 5.10 I 3495 I I 1994 i 0.00 I 5095 I 1255.47 I 52.S4 1 65.95 1 34.68 5.10 1 3495 1 I 1995 I 0.00 I 5095 I 1255.47 I 53.56 I 67.24 I 34.68 5.10 1 3495 I I 1996 I 0.00 I 50951 11255.47 I 54.56 I 68.50 I 34.68 5.10 I 3495 I I 1997 I r-.00 I 50951 11255.47 1 55.58 I 69.78 1 34.68 5.10 1 3495 I I 1998 I 0.001I 50951 I1255.4? I i6.63 1 71.10 1 34.68 5.10 I 3495 I I 19991I 0.00 I 5095 I 1255.47 1 57.50 I 72.19 1 34.68 5.10 1 3495 1 I 2000 1 0.00 I 5095 I 1255.47 I 58.38 I 73.29 1 34.68 5.10 I 3495 1 I 2001 I 0.00 I 5095 11255.47 I 58.69 I 73.68 1 34.68 5.10 1 3495 I I 2002 1 0.00 I 5095 I 1255.47 I 59.00 I 74.07 I 34.68 5.IC I 3495 I I 2003 I 0.00 I 5095 I 1255.47 I 59.00 1 74.07 I 34.68 5.10 I 3495 I I 2004 i 0.00 I 5095 I 1255.47 I 59.00 I 74.07 I 34.68 5.10 1 3495 I I 2005 I 0.00 I 5095 I 1255.47 I 59.00 I 74.07 I 34.68 5.10 I 3495 I I 2006 I 0.00 I 5095 11255.47 I 59.00 I 74.07 I 34.68 5.10 I 3495 1 I 2007 I 0.00 1 5095 I 1255.47 1 59.00 I 74.07 I 34.68 5.10 I 3495 I I 2008 I 0.00 I 5095 I 1255.47 I 59.00 I 74.07 1 34.68 5.10 I 3495 I I 2009 1 0.00 I 50951 I1255.47 I 59.00 1 74.07 I 34.68 5.10 I 3495 I I 2010 I 0.00 1 50951 11255.47 I 59.00 1 74.07 I 34.68 5.10 I 3495 I I 2011 I 0.00 i 5095 I 1255.47 1 59.00 I 74.07 1 34.68 5.10 I 3495 I 1 2012 1 0.00 I 5095 I 1255.47 I 59.00 I 74.07 1 34.68 5.10 I 3495 I I 2013 I 0.00 1 5095 I 1255.47 I 59.00 I 74.07 1 34.68 5.10 I 3495 I I 2014 1 0.00 i 50951 11255.47 1 59.00 1 74.07 1 34.68 5.10'1 3495 1 I 2015 I -75.40 I 5095 I 1255.47 I 59.00 I 74.07 I 34.68 5.10 I 3495 I lOiscount rate I 0.0041 8.00,41 11.0041 13.0041 14.0041 16.0041 lAverage fuel cost I 2.06 I 2.01 I 2.00 1 1.99 I 1.98 I 1.97 I I cts/kWIu I I I I I I I [Average O.M.R. costl 1.14 I 1.14 I 1.14 I 1.14 1 1.14 I 1.14 I I cts/kItII I I I lAverage capital I 0.81 I 2.33 I 3.13 I 3.72 1 4.04 I 4.72 I [cost ctslkWh I I I I I I I-- - - - -- - - - -I-- -- --I-- -- -- I-- - -- -I-- -- -- I-- - -- -I-- -- -- [Average electricityl 4.01 1 5.49 1 6.26 1 6.85 1 7.17 I 7.84 I Icost cts/kWh I I I I I II I-- - - - -- - - - -I-- -- --I-- - - - I-- - -- -I-- - - - I-- -- -- -- -- - IGas netback value I I I I II I USSIICF I 5.42 1 6.88 1 7.72 1 8.38 1 8.74 1 9.51 1 1 uSS/POIBTU I 4.38 1 5.S6 1 6.24 1 6.78 1 7.07 I 7.70 1 I US$IGCal I 17.4 1 22.1 I 24.8 1 26.9 1 28.0 1 30.5 1 8REAI(OOVN OF NETBACK VALUE IDiscount rate I 0.0041 8.0041 11.0041 13.0041 14.0041 16.0041 I Capital different.1 I I I I I I US$/ MWBTU I 0.41 1 1.65 1 2.36 1 2.91 I 3.20 1 3.85 1 I US$/ GCaI I 1.64 1 6.57 1 9.36 1 11.53 1 12.71 1 15.26 1 1 OMWRcost differentl I I I I I I I US$/ 1148TU I 1.11 I 1.111I 1.11 I 1.11 I 1.11 I 1.111I I ~ ~~I I I I I I I I Fuel efficiency I I I I I I I I diff. US$/ III8TU I 0.57 I 0.55 1 0.55 I 0.55 I 0.55 I 0.54 I I Fuel I I I I I I I I cost US$/ IIBTU I 2.29 1 2.24 1 2.23 1 2.21 I 2.21 I 2.20 1 -------- -I ----I ----I -----I ----I -----I ----- Capital cost : 1100 S/KM including 100 $/KW for FGO availability differential Is taken into account by setting: - 66.b 4 load factor for Comrbined Cycle plant with 600 NW to procuce 3495 GWN /yearj - 58.2 % load factor for Coal plant with 608 MW to produce 3495 0Mb /year Anex 8 Page 3 of 4 B. Netback Value of Ga In Cenvaitlonel Steam Plant Table lit Sl..1t1.m of aa0-UInd Ste4m1 PI Mt Capacity U1 s First yew 191 Lo tfactor a/y 4 () St?t-w yew 1992 Consumption STU/lkVh 853 0 A(40) Lifetime yea: 19 Gas LHV BTU/cft: 1236 Start-up load 70* Monetary unit us S Investwnt (mil1.): S10 (1) I lInvestment I Operat.l GAS I GAS I Fixed Variable I I Year I I Rate I Conswition I cost I Cost Cost I i------- _ I------- _____ I - ---.-- --II - I- ------ I I I miI1ion $ I hrs/y I Bcf/y lcfd Imillion SI million S I I-------I----- -- - ----- ---I--- ----- ------------- 1 1986 1 o.o I I 1 1987 1 0.001 I 1 1 1 1988 1 51.001 I I I I 1989 1 127.50 I I ' I 1990 1 178.50 1 1 ' ' I I 1991 1 153.00 1 1 1 1 I I 1992 I 0.00 1 3255 1 13.48 36.93 1 81.30 1 10.46 1.31 1 1 1993 1 0.00 I 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 1 1 1994 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 1 1 1995 I 0.00 i 4650 1 19.2S 52.75 1 116.14 1 10.46 1.31 1 ! 1996 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 1 1 1997 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 1 1 1998 1 0.00 1 4650 1 19.25 .52.75 1 116.14 1 10.46 1.31 1 1 1999 1 0.00 1 4650 ! 19.25 52.75 1 116.14 1 10.46 1.31 1 1 2000 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 1 1 2001 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 1 1 2002 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 1 1 2003 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 1 1 2004 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 1 a I j6 i i.2 52.75 1 11C.: ! ^ !_-t I 1 2006 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 i 1 2007 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 1 1 2008 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 1 1 2009 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 1 1 2010 1 -51.00 I 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 1 Gas price - breakeven price at 13* d.r. US$/MIITU 4.88 IDiscount rate I 0.00*1 8.00*1 11.00*1 13.00%1 14.00*1 16.00%1 lAverage fuel cost I 4.16 1 4.16 1 4.16 1 4.16 1 4.16 1 4.16 1 I cts/kWh I I I I I I I lAverage O.M.R. costl 0.43 1 0.43 1 0.44 1 0.44 I 0.44 ' 0.44 ' I cts/kWh I I I I I I I lAverage capital I 0.88 1 2.10 1 2.70 1 3.15 1 3.38 1 3.88 1 Icost cts/kWh I I I I I I I I _ ___I--- - I - I- I _ I lAverage electricityl 5.47 1 6.70 1 7.30 1 7.75 1 7.99 1 8.48 1 Icost cts/kWh I I I I I I I (1) Capital cost 850 I/KW Page 4 of 4 Table St: S.Iletl.. of 0W -Flrd Stem PIe| Capacity 1 Go First wr : 1 Load fator hW/y : t (53S) Stat-. yr : t0 Consumption BTU/kWh: 7SO () Lifatlu ts o Fuel oil LHV 8TU/kg : 38900 Start-up usd : 70l Monetary unit US S Investment (mill.): 540 (1) I Ilnvestment I Operat.1FUEL OIL IFUEL OIL IFUEL OIL a Fixed Variable I I Year I I Rate IConsuwpt.1 Price I Cost I Cost Cost I I I mil;ionS I hrs/y 1000 Tons I S/Ton Imillion Sl milltan S I 1 1986 1 0.00 1 I I I I I 1 1987 1 0.001 1 1 1 1 1988 1 54.00 1 1 1 1 I 1 1989 1 108.00 1 1 1 122.4 1 1 I 1990 1 216.00 1 1 1 144.7 1 1 1 1 1991 1 162.00 1 1 1 147.5 1 1 1 1 1992 1 0.00 1 3255 1 439.30 1 150.3 1 66.03 1 11.61 i9 I 1 1993 1 0.00 1 4650 1 627.57 1 153.2 1 96.14 1 11.61 4.69 1 1 1994 1 0.00 1 4650 1 627.57 1 156.2 1 98.03 1 11.61 4.69 1 1 1995 1 0.00 I 4650 i 627.57 1 160.9 1 100.98 1 11.61 4.69 1 1 1996 I 0.00 1 4650 1 627.57 1 165.9 1 104.11 1 11.61 4.69 1 1 1997 1 0.00 1 4650 1 627;57 1 171.! 1 107.3PJ I 11.l1 4.69 1 1 1998 1 0.00 1 4650 I 627.57 1 176.4 1 110.70 1 11.61 4.69 1 I 1999 ' 0.00 1 4650 1 627.57 1 179.4 1 112.59 1 11.61 4.69 1 1 2000 1 0.00 1 4650 1 627.57 1 182.5 1 114.53 1 11.61 4.69 1 1 2001 1 0.00 1 4650 1 627.57 1 185.7 1 116.54 1 11.61 4.69 1 1 2002 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1 1 2003 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1 1 2004 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1 I 2005 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1 1 2006 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1 1 2007 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1 1 2008 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1 1 2009 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1 1 2010 1 -54.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1 I----------------------------------------------------------------------- Fuel oil price S:ton: 150.3 (in 1992) Price to KEPCO excludes wholesale margin I1iscount rate I 0.001 8.00S1 11.00S1 13.0041 14.00S1 16.00S1 - __I------- _I-------- _I-- -- -- _I--_- _I- - _I lAverage fuel cost 1 4.01 1 3.90 1 3.85 1 3.83 1 3.82 1 3.79 1 .1 cts/kwh I I I I I I I lAverage O.n.R. costl 0.59 1 0.60 I 0.60 I u.61 1 0.6O I U.bl I I cts/kwh I I I I I I I lAverage capital 1 0.93 1 2.22 1 2.85 1 3.31 1 3.56 1 4.08 1 Icost cts/kWh I I I I I I I I------------------- _I------- _I- - _I- - _I- - _I- - _I- - __I lAverage electricityl 5.54 1 6.71 1 7.31 1 7.75 1 7.98 1 8.48 1 Icost cts/kWih I I I I I I I I ------ _ _ _ _ _ _ I lGas netback value I I I I I I I I US$/MCF I 6.13 1 6.05 1 6.G4 1 6.03 1 6.03 1 6.02 I I US$/M8BTU I 4.961 4.901 4.881 4.88 1 4.881 *.87 1 I U.S/GCal I 19.68 1 19.44 1 19.38 1 19.36 1 19.35 1 19.34 1 Fuel oil price S/ton: 150.3 BREAKDOWN OF NET8ACK VALUE -FUEL OIL PLANT- 10iscount rate I 0.0041 8.00S1 11.0041 13.00S1 14.0041 I ----- _ __ ______ _. _ I ICapital + OM cost I I I I I I 1diff. US$/ MMDTU I 0.25 1 0.33 1 0.37 1 0.39 1 0.40 1 I US$/ GCal I 1.01 1 1.31 1 1.45 1 1.55 1 1.60 1 IFuel I I I I I I Icost US$/ srTU I 4.71 1 4.57 1 4.52 1 4.49 1 4.471 -------- ___ _____ ______ I ____ I (1) Capital Cost: 900 S / KW of 6 KONtEA OAS UTILIZATION STUOY Oae Oomand Scenarlo. K O R E A G A S S T U D Y S c e n a r i o s A . C .D NATURAL AS SU PPLY /OEMAND PR06RAN" Th_aTGns LNG I I C I T Y G A S 1 0 0 0 T o n s I P O W E R I T O T A Li I I I Coot Cyc Steam Total I I I I KYONGIN CENTRAL YONGNAM HONAM SOUTH TOTAL I North Plants I L N G I 1 1988 1 1 1 1989 1 361 361 1639 1639 2000 1 1 1990 1 473 473 1527 1527 2000 1 11991 1 586 586 1415 1415 2000 1 i 1992 1 698 698 325 1477 1802 2500 1 1 1993 1 798 61 859 800 1341 2141 3000 1 1 1994 1 877 79 956 1252 1292 2544 3500 1 1 1995 1 960 105 1065 1252 1683 2935 4000 1 11996 1 1053 137 277 76 1543 1252 1705 2957 4500 1 11997 1 1152 156 328 100 1736 1252 2012 3264 5000 I 1 1998 1 1250 187 388 134 1959 1577 1964 3541 5500 1 11999 1 1366 216 460 178 2220 1902 1879 3781 6000 1 1 2000 1 1488 252 544 236 2520 1902 1578 3480 6000 1 1 2001 1 1619 297 644 314 102 2976 1902 1622 3524 6500 1 1 2002 1 1733 33C 736 362 115 3284 2553 1163 3716 7000 1 1 2003 1 1848 380 829 410 128 3595 2553 1352 3905 7500 1 1 2004 1 1963 42 922 458 141 3906 3203 1391 4594 8500 1 1 2005 1 2078 464 1015 507 15 4219 3203 1078 4281 8500 I 12006 1 2193 S06 1106 55 166 4530 3203 1267 4470 9000 I 12007 1 2298 545 1200 603 1I8 4827 3203 970 4173 9000 1 Thousand Tons ING I i S c e n a r i o A. I S c e n a r i o B. I S c e n a r i o C. I S c e n a r i o D. I I I K Y O H G I N I + C E N T R A L I + Y O N G NAN I + H ON A 1 I I l TOTAL City Total I TOTAL City Total I TOTAL City Total I TOTAL City Total I I I LNG gas Power I LNG gas Power I LNG gas Power I gas Power I - _ _- I------------------------I- I I I (2) 1 (2) I (2) 1 (2) I 1 1989 1 2000 361 1639 2000 361 1639 2000 361 1639 2000 361 1639 1 1 1990 1 2000 473 1527 2000 473 1527 2000 473 1527 2000 473 1527 1 1 1991 1 2000 586 415 2000 586 1415 2000 586 1415 2000 586 1415 1 1 1992 1 2500 698 1802 2500 698 1802 2500 698 1802 2500 698 1802 1 1 1993 1 2940 798 2142 3000 859 2141 3000 859 2141 3000 859 2141 1 1 1994 1 3400 877 2523 3500 956 2544 3500 956 2544 3500 956 2544 1 1 1995 1 3900 960 2940 4000 1065 2935 4000 1065 2935 4000 1065 2935 ' 1 1996 1 4000 1053 2947 4150 1190 2960 4400 1467 2933 4500 1543 2957 1 1 1997 1 4400 1152 3248 4600 1308 3292 4900 1636 3264 5000 1736 3264 1 I 1998 1 4800 1250 3550 5000 1437 3563 5400 1825 3575 5500 1959 3541 1 1 1999 1 5100 1366 3735 5400 1582 3819 5800 2042 3759 6000 2220 3781 1 1 2000 1 4950 1488 3462 5400 1740 3660 5800 2284 3516 6000 2520 3480 1 1 2001 1 5100 1619 3481 5450 1916 3534 6100 2560 3540 6400 2874 3526 1 1 2002 1 5450 1733 3717 5800 2071 3729 6500 2807 3693 7000 3169 3831 i 1 2003 1 5750 1848 3902 6150 2226 3922 7000 3057 3943 7400 3467 3933 1 1 2004 1 6550 1963 4587 7000 2385 4615 7900 3307 4593 8400 3765 4635 1 1 2005 1 6350 2078 4272 7000 2542 4458 7900 3557 4343 8400 4064 4336 1 i 2006 1 6650 2193 4457 7100 2699 4401 8200 3807 4393 8850 4362 4488 1 i 2007 1 6450 2298 4152 7100 2843 4257 8200 4043 4157 8850 4646 4204 1 -- - - - - - - - -- - - - - - - - Base of Demand projections Basic Plan for LNG National Supply Project' September 1989 - S K. SHIN - Ministry of Energy and Resources - (1) Gas consuiption in Poeer generation as in Basic LNG Plan Report (2) Gas consuiption in Porer generation adjusted in each scenario for smoothing LNG supply K O R E A G A S S T U D Y S c e n a r i o A. N A T U R-A-L G A S S-U P-P L- Y / D E MA--NOD P-R O-G-R-A-M Thousand Tons LNG I R E S I D E N T I A L I C O N M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL I I I I I TRY I I I I I I I I I I IL H G I I Cooking Total I Operat- Adminis- Total I I City I Combin Steam Total I l I Heating I ional trative I I gas I Cycles Plants I I 11988 1 1 11989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 0 1639 1639 2000 1 1 1990 1 92 60 152 37 107 143 178 473 .0 1527 1527 2000 1 I 1991 1 106 77 182 46 134 1'79 224 586 0 1414 1414 2000 1 11992 1 119 94 213 54 160 214 271 698 325 1477 1802 2500 1 1 1993 1 133 111 244 62 176 238 316 798 800 1342 2142 2940 1 0 11994 1 147 128 275 69 193 262 340 877 1252 1271 2523 3400 1 1 1995 1 160 148 308 77 209 286 365 960 1252 1688 2940 3900 1 11996 1 178 171 349 85 231 316 389 1054 1252 1694 2946 4000 1 1 1997 1 195 198 393 95 253 348 411 1152 1252 1996 3248 4400 1 1 1998 1 213 228 441 105 281 386 424 1251 1577 1972 3549 4800 1 1999 1 230 268 498 115 309 424 443 1366 1902 1832 3734 5100 1 ! 2000 1 247 312 559 126 336 462 467 1488 1902 1560 3462 4950 1 1 2001 1 265 355 620 136 364 500 499 1619 1902 1579 3481 5100 1 !2002 1 280 399 679 146 391 537 518 1733 2553 1164 3717 5450 1 12003 1 294 442 736 156 417 573 540 1848 2553 1349 3902 5750 1 12004 1 307 486 793 166 443 609 561 1963 3203 1384 4587 6550 1 !2005 1 320 529 849 176 469 645 584 2078 3203 1069 4272 6350 1 1 2006 1 332 573 905 186 497 682 606 2193 3203 1254 4457 6650 1 !2007 1 345 616 961 195 522 717 619 2298 3203 949 4152 6450 1 (1) Total LNG import figures are rnunded, and the difference is absorbed by Steam Power Plants acting as swing consumers. The Combined Cycle programme, however, is fixed with the same schedule for the scenarios A and B. K O R E A G A S S T U D Y S c e n a r i o B. N A T U-R A-L G A-S S U P P-L- Y / D-E M-A N-D P-R-O G-R A-M Thousand Tons LNG I R E S I D E N T I A L I C O M M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL I I I I TRY I I I I I I I I I I L N G I I I Cooking Total I Operat- Adminis- Total I I City I Coffbin Steam Total I I I Heating I ional trative I I gas ICycles Plants I I --I I I- - I I I 11988' I !1989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 1639 1639 2000 1 11990 1 92 60 152 37 107 143 178 473 1527 1527 2000 1 I1991 1 106 77 182 46 134 i79 224 586 1414 1414 2000 1 1992 1 119 94 213 54 160 214 271 698 325 1477 1802 2500 1 11993 1 145 121 266 67 192 260 334 859 800 1341 2141 3000 1 1 1994 1 162 141 303 76 213 289 364 956 1252 1292 2544 3500 1 !1995 1 180 166 346 86 236 322 397 1065 1252 1683 2935 4000 1 1 1996 1 204 196 400 97 266 363 427 1191 1252 1707 2959 4150 1 11997 1 225 227 452 109 293 402 454 1308 1252 2040 3292 4600 1 1 1998 1 249 265 514 123 328 451 472 1438 1577 1985 3562 5000 1 ! 1999 1 272 314 586 136 365 501 495 1582 1902 1916 3818 5400 1 1 2000 1 296 369 665 '50 402 552 523 1740 1902 1758 3660 5400 1 12001 1 322 427 750 165 442 608 559 1916 1902 1632 3534 5450 1 12002 1 345 485 830 1i9 480 659 582 2071 2553 1176 3729 5800 1 1 2003 1 365 544 910 193 517 710 608 2228 2553 1369 3922 6150 1 12004 I 386 604 990 207 555 ;62 633 2385 3203 1412 4615 7000 1 2005 1 405 663 1068 221 592 813 661 2542 3203 1155 4358 6900 1 2006 1 423 723 1147 235 630 865 687 2699 3203 1298 4501 7200 1 12007 1 441 782 1223 249 666 915 706 2843 3U03 1054 4257 7100 1 --------------------------------_------------------------- ----------------0 (1) Total LNG import figures are rounded, and the difference is absorbed by Steam Power Plants acting as swing consumers. The Combined Cycle programme, however, is fixed with the same schedule for the scenarios A ard B. K O R E A G A S S T U D Y S c e n a r i o C. N A T U R A L G A S S U P P L Y / D E M A N D PROGR,AM Thousand Tons LNG I I R E S I D E N T I A L I C O M M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL I | I I I TRY I I I I g I I I I I I L N G I I I Cooking Total I Operat- Adminis- Total I I City I Combin Steam Total I I I Heating I ional trative I I gas I Cycles Plants I I 11988 11 11989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 1639 1639 2000 1 I 1990 1 92 60 152 37 107 143 178 473 1527 1527 2000 1 I 1991 1 106 77 182 46 134 179 224 586 1414 1414 2000 1 1 1992 1 119 94 213 54 160 214 271 698 325 1477 1802 2500 1 1 1993 1 145 121 266 67 192 260 334 859 800 1341 2141 3000 1 1 1994 1 162 141 303 76 213 289 364 956 1252 1292 2544 3500 1 I 1995 I 180 166 346 86 236 322 397 1065 1252 1683 2935 4000 1 i1996 1 251 232 483 118 328 447 538 1468 1252 1780 3032 4500 1 1 1997 1 280 272 552 134 365 499 586 1636 1252 2TI2 3364 5000 1 1 1998 1 313 321 634 153 412 565 627 1826 1377 2097 3674 5500 1 I 1999 1 347 382 729 172 462 634 679 2042 1902 2056 3958 6000 1 1 2000 1 384 453 836 192 516 707 740 2284 1902 1814 3716 6000 1 1 2001 1 424 531 955 215 574 789 817 2560 1902 2038 3940 6500 1 1 2002 1 458 607 1065 235 630 865 876 2807 2553 1640 4193 7000 1 I 2003 1 489 689 1178 256 683 939 940 3057 2553 1890 4443 7500 1 1 2004 1 520 773 1293 276 737 1012 1002 3307 2?03 1990 5193 8500 1 12005 1 549 856 1405 295 790 1085 1067 3557 3203 1740 4943 8500 1 12006 1 577 941 1518 315 844 1159 1130 3807 3203 1990 5193 9000 1 12007 1 6U3 1025 1628 335 895 1230 1186 4043 3203 1754 4957 9000 1 m 0 (1) Total LNG import figures are rounded, and the difference is absorbed by Steam Power Plants ^ acting as swing consumers. The Combined Cycle programme. however, is fixed with the same schedule for the scenarios A and B. _- K O R E A G A S S T U D Y S c e n a r i o C . N A TuR AL G AS S U P PLY /DOEM A ND P RO GR AM Thousand TonlsLN6 I I R E S I D E N T I A L I C O M M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL I I I I TRY I I I I I I I I I I I L N G I I I Cooking Total I Operat- Adminis- Total I I City I Combin Steam Total I I I I Heating I ional trative I I gas I Cycles Plants I I 1 19881 1 1 1989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 1639 1639 2000 1 I 3990 1 91.9 60.2 152.0 36.7 106.7 143.4 177.7 473.1 1527 1527 2000 1 I 1991 1 105.6 76.8 182.4 45.5 133.6 179.1 224.2 585.7 1414 1414 2000 1 1 1992 1 119.3 93.8 213.1 54.4 160.1 214.5 270.7 698.3 325 1477 1802 2500 1 1 1993 1 144.9 120.7 265.6 67.2 192.5 259.7 333.9 859.1 800 1341 2141 3000 1 1 1994 1 161.9 140.8 302.8 76.4 213.0 289.4 3638 956.0 1252 1292 2544 3500 1 1 1995 1 180.5 165.6 346.1 86.4 235.6 322.0 397.0 1065.1 1252 1683 2935 4000 1 1 1996 1 250.7 232.3 483.1 118.5 328.1 446.5 538.0 1467.6 1837 1695 3532 000 1 1 1997 1 279.6 272.5 552.0 134.4 364.5 498.9 585.5 1636.5 1837 1527 3364 5000 1 1 1998 1 312.8 320.8 633.5 153.0 412.0 564.9 627.3 1825.8 2487 1687 4174 6000 1 I 1999 1 346.8 382.4 729.1 172.1 461.7 633.8 678.9 2041.8 2813 2145 4958 7000 1 ! 2000 1 383.6 452.8 836.4 191.9 515.6 707.5 740.4 2284.3 2813 1903 4716 7000 1 1 2001 1 424.0 530.6 954.6 214.7 574.3 789.0 816.8 2560.5 2813 1627 4440 7000 1 1 2002 1 458.1 607.2 1065.4 235.4 629.7 865.2 876.5 2807.0 3463 2230 5693 8500 1 1 2003 1 489.4 689.0 1178.4 255.6 683.3 938.9 939.9 3057.1 3463 1980 5443 8500 1 1 2004 1 520.1 772.8 1292.8 275.6 736.9 1012.5 1001.6 3306.9 4113 2080 6193 9500 1 1 2005 1 548.8 856.3 1405.1 295.4 789.5 1084.9 1066.7 3556.7 4113 1830 5943 9500 1 1 2006 1 576.6 941.3 1517.9 315.4 843.7 1159.0 1130.2 3807.1 4113 2080 6193 10000 I 1 2007 1 602.7 1025.1 1627.8 334.8 894.9 1229.6 1185.6 4043.0 4113 1844 5957 10000 I (1) Total LNG import figures are rounded, and the difference is absorbed by Steam Power Plants 4! acting as swing consumers. In scenario Cl, the Combined Cycle plants schedule is increased in order to obtain the same economic profitability as in scenario C . a K O R E A G A S S T U D Y S c e n a r i o D. N A T U R-A-L G A- S S U P P-L- Y /DO E M-A N-D P-R-O-G R-A-M Thousand Tons LNG I R E S I D E N T I A L I C O M M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL I I I I I TRY I I I I I I I I I I IL N G I I Cooking Total I Operat- Adminis- Total I I City I Combin Steam Total I I I Heating I ional trative I I gas I Cycles Plants I I 1 1988 I 1 1989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 1639 1639 2000 1 I 1990 1 92 60 152 37 107 143 178 473 1527 1527 2000 1 1 1991 1 106 77 182 46 134 179 224 586 1414 1414 2000 1 1 1992 1 119 94 213 54 160 214 271 698 325 1477 1802 2500 1 1 1993 1 145 121 266 67 192 260 334 859 800 1341 2141 3000 1 1 1994 1 162 141 303 76 213 289 364 956 1252 1292 2544 3500 1 1 1995 1 180 166 346 86 236 322 397 1065 1252 1683 2935 4000 1 1 1996 1 261 241 502 123 342 466 576 1544 1252 1704 2956 4500 1 1 1997 1 294 284 578 141 384 525 634 1736 1252 2012 3264 5000 1 1 1998 1 333 338 671 162 438 601 688 1960 1577 1963 3540 5500 1 I 1999 1 376 409 785 186 499 685 750 2220 1902 1878 3780 6000 1 1 2000 1 422 489 911 210 565 775 835 2520 1902 1578 3480 6000 1 2001 1 474 581 1055 239 639 878 942 2874 1902 1624 3526 6400 1 2002 ! 514 667 1181 263 704 967 1021 3169 2553 1278 3831 7000 1 i 2003 1 551 760 1311 286 766 1052 1104 3467 2553 1380 3933 7400 1 2004 1 587 857 1443 309 827 1137 1185 3765 3203 1432 4635 8400 1 !2005 ! 621 953 1573 332 888 1221 1270 4064 3203 1133 4336 8400 1 2006 ! 653 1051 1704 355 951 1306 1352 4362 3203 1335 4538 8900 1 2007 1 684 1147 1831 378 1010 1388 1427 4646 3203 1051 4254 8900 1 m m (1) Total LNG import figures are rounded, and the difference is absorbed by Steam Power Plants acting as swing consumers. The Combined Cycle programme, however, is fixed with the same schedule for the scenarios A and B. -S I _ - 135 - Annex 10 KOREA Page 1 of 5 GAS UTILIZATION STUDY Natura! Gam Supply/OD_mnd Progra K Y O N G I N A R E A S c e n a r i o A. N A T U R A L G A S S U P P L Y / O E M A N O P R O G R A N I I LNG SUPPLY I DEMAND 1411 ion M3/Year I TOTAL I POWER DEMAND I I I I I I (1) I I I K.Tons Mili.M3 IHouseh Conmrc. Industry INON POWER IComb Cyc Steam Pt I I I I I I I 1988 I 1926 2277 97 56 59 212 2065 1 I 1989 I 2000 2364 144 125 157 427 1937 I I 1990 I 2000 2364 180 169 210 559 1805 I I 1991 I 2000 2363 216 212 265 692 1671 1 11992 I 2500 2955 252 253 320 825 384 1746 1 11993 I 2940 3474 289 281 373 943 945 1586 I 11994 1 3400 4019 325 310 402 1037 1480 1502 I 11995 I 3900 4609 365 338 432 1135 1480 1995 1 1 1996 1 4000 4728 412 373 460 1245 1480 2003 1 I 1S97 I 4400 5201 465 411 486 1362 1480 2359 1 1 1998 1 4800 5674 521 456 501 1478 1864 2331 1 I 1999 1 5100 6028 589 501 524 1614 2248 2165 1 1 2000 1 4950 5851 661 546 552 1759 2248 1844 I 1 2001 1 5100 6029 733 591 590 1914 2248 1866 I 1 2002 1 5450 6442 802 634 612 2048 3017 1377 I 1 2003 1 5750 6796 870 677 638 2184 3017 1594 1 1 2004 1 6350 7506 937 720 663 2320 3786 1400 I 1 2005 1 6350 7506 1004 762 690 2456 3786 1264 1 ! 2006 1 6450 7624 1070 806 716 2592 3786 1246 I ! 2007 1 6450 7624 1136 848 732 2716 3786 1122 1 P R E S E N T V A L U E A T : 13 p.cent .................... T o t a I P r o g r a m m e US $/GCal 24.26 27.07 25.86 20.20 24.35 27.13 22.04 US S/MMBTU 6.11 6.82 6.52 5.09 6.14 6.84 5.55 Mill.US$ 7917 876 727 636 2239 2725 2953 Billion H3 29.67 2.94 2.56 2.86 8.36 9.13 12.18 C o n t i n u a t i o n o f p r e s e n t s i t u a t i o n US $/GCal 17.65 17.89 19.05 15.58 17.38 17.71 US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46 Mill.USs 3139 194 180 184 558 2581 . Billion M3 16.17 0.99 0.86 1.07 2.92 13.25 I n c r e m e nt a l b a s i s s t a r t i n g i n 1 9 9 0 US $/GCal 32.17 31.70 29.31 22.96 28.08 27.13 n.m. US $/HMBTU 8.11 7.99 7.39 5.79 7.08 6.84 n.m. Mill.USS 4777 682 547 452 1681 2725 372 Billion M3 13.50 1.95 1.70 1.79 5.44 9.13 -1.07 ................................................................................... P R E S E N T V A L U E A T : 8 p.cent .................... T o t a I P r o g r a m m e. US S/GCal 23.00 27.67 26.39 20.62 24.93 22.23 22.21 US $/MMBTU 5.80 6.97 6.65 5.20 6.28 5.60 5.60 Mill.USS 10742 1390 1127 957 3474 3628 4045 Billion M3 44.07 4.57 3.88 4.22 12.67 14.84 11.82 C o n t i n u a t i o n o f p r e s e n t s i t u a t I o n US $/GCal 17.65 17.89 19.05 15.58 17.38 17.71 US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46 Mill.US$ 430! 266 246 252 765 3537 Billion M3 22.16 1.35 1.18 1.47 4.00 18.15 I n c r e m e nt a l b a s i s s t a r t i n g I n 1 9 9 0 US $/GCal 28.60 31.78 29.58 23.32 28.41 22.23 n.m. US $/MMBTU 7.21 8.01 7.45 5.88 7.16 5.60 n.m. Mill.USS 6894 1124 881 705 2710 3628 556 Billion M3 21.91 3.21 2.71 2.75 8.67 14.84 -1.60 (I) Gas supplied to Steam power plants is the volume of gas remaining after meeting the needs of non power demand' for the whole Country, and the needs of of Combined Cycle plants considered as priority gas consumers. Annex 10 - 136 - Page 2 of 5 K Y O N G I N + C H U N G C H O N G A R E A _--- -- ----- ----- ----------------- S c e n a r i o B. N A T U R A L G A S S U P P L Y / D E M A N D P R O G R A M I I LNG SUPPLY I DEMAND Million M3/Year I TOTAL I POWER DEMAND I I I I I I (1) 1 I I K.Tons MilIl.M3 IHouseh Commerc. Industry INON POWER IComb Cyc Steam PI ----------------------_----------------------------------------------------------! I 1988 I 1926 2277 97 56 59 212 2065 1 1 1989 1 2000 2364 144 125 157 427 1937 I I 1990 ! 2000 2364 180 169 210 559 1805 I !1991 ! 2000 2363 216 212 265 692 1671 ! 1 1992 I 2500 2955 252 253 320 825 384 1746 I 1 1993 ! 3000 3546 313 307 395 1015 945 1586 I I 1994 I 3500 4137 358 342 430 1130 1480 1527 i I 1995 I 4000 4728 409 381 469 1259 1480 1990 1 1 1996 1 4150 4906 473 429 505 1407 1480 2019 1 1 1997 I 4600 5438 537 473 535 1546 1480 2412 1 1 1998 I 5000 5909 608 533 558 1699 1864 2346 1 1 1999 1 5400 6383 692 593 585 1869 2248 2265 I 1 2000 1 5400 6383 787 652 618 2057 2248 2078 1 1 2001 1 5450 6442 886 718 661 2265 2248 1929 1 1 2002 1 5800 6856 981 779 688 2448 3017 1391 1 1 2003 I 6150 7270 1075 839 718 2633 3017 1620 1 1 2004 1 7000 8274 1170 901 748 2819 3786 1669 1 1 2005 1 7000 8274 1263 961 781 3005 3786 1483 i I 2006 I 7100 8393 1355 1023 8i2 3190 3786 1417 I I 2007 I 7100 8392 1447 1079 834 3360 3786 1247 I P R E S E N T V A L U E A T : 13 p.cent .................... T o t a I P r o g r a m m e US S/GCal 24.43 28.13 26.05 20.28 24.90 27.13 22.10 US $IMMBTU 6.16 7.09 6.56 5.11 6.28 6.84 5.57 Mill.US$ 8331 1050 841 691 2582 2725 3024 Billion M3 31.00 3.39 2.93 3.10 9.43 9.13 12.44 C o n t i n u a t i o n o f p r e s e n t s i t u a t i o n US $/GCal 17.65 17.89 19.05 15.58 17.38 17.71 US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46 Mill.USS 3139 194 180 184 558 2581 Billion M3 16.17 0.99 0.86 1.07 2.92 13.25 I n c r e m e n t a l b a s i s s t a r t i n g i n 1 9 9 0 US $/GCal 31.83 32.33 28.95 22.77 28.28 27.13 n.m. US S/MMBTU 8.02 8.15 7.29 5.74 7.13 6.84 n.m. Mill.US$ 5192 856 661 507 2024 2725 443 Billion M3 14.83 2.41 2.08 2.02 6.51 9.13 -0.81 .. ........ ...................... .. ............ .................... ..... I........... ....... . P R E S E N T V A L U E A T : 8 p.cent .................... T o t a I P r o g r a m m e US $/GCal 23.27 28.73 26.56 20.70 25.50 22.23 22.27 US $/MMBTU 5.86 7.24 6.69 5.22 6.43 5.60 5.61 Mlill.US$ 11406 1692 1324 1048 4G65 3628 4171 Billion M3 46.36 5.36 4.53 4.60 14.49 14.84 17.03 C o n t i n u a t i o n o f p r e s e n t s i t u a t i o n US S/GCal 17.65 17.89 19.05 15.58 17.38 17.71 US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46 Mill.US$ 4301 266 246 252 765 3537 Billion M3 22.16 1.35 1.18 1.47 4.00 18.15 I n c r e m e n t a I b a s i s s t a r t i n g i n 1 9 9 0 US S/GCal 28.59 32.39 29.19 23.10 28.59 22.23 n.m. US $/MMBTU 7.20 8.16 7.36 5.82 7.21 5.60 n.m. Mili.US$ 7611 1426 1078 796 3300 3628 682 Billion M3 24.20 4.00 3.36 3.13 10.49 14.84 -1.13 (I) Gas supplied to Steam power plants is the volume of gas remailning after meeting the needs of non power demand for the whole Country. and the needs of Combined Cycle plants considered as priority gas consumers. 10 Page 3 of 5 - 137 - K Y O N G I N / CHUNG CHO NG/ Y ONG NAM A R E A S c e n a r i C. N A T U R A L G 4 S S U P P L Y / O E N A N O P R O G R A M I I LNG SUPPLY I DEMAND Million M3/Year I TOTAL I POWER DEMAND I I I I I I (1) 1 I I K.Tons Mill.M3 lHouseh Commerc. Industry INON POWEP IComb Cyc Steam Pi - . . . I 1 1988 1 1926 2277 97 56 59 212 2065 1 ! 1989 ! 2000 2364 144 125 157 427 1937 1 !i 1990 2000 2364 180 169 210 559 1805 i I1991 ! 2000 2364 216 212 265 692 1672 ! 1 1992 1 2500 2955 252 253 320 825 384 1746 1 I 1993 I 3000 3546 313 307 395 1015 945 1586 I 1 1994 1 3500 41j7 358 342 430 1130 1480 1527 I 1 1995 1 4000 4727 409 381 469 1259 1480 1989 1 ! 1996 1 4400 5201 571 528 636 1735 1480 1986 1 1 1997 1 4900 5792 653 590 692 1934 1480 2378 1 1 1998 ! 5400 6383 749 668 741 2158 1864 2361 1 ! 1999 1 5800 6855 862 749 802 2413 2248 2194 1 ! 2000 I 5800 6856 989 836 875 2700 2248 1908 ! ! 2001 ! 6100 7211 1128 933 965 3026 2248 1936 1 1 2002 i 6500 7683 1259 1023 1036 3318 3017 1348 1 1 2003 1 7000 8273 1393 1110 1111 3614 3017 1643 1 1 2004 ! 7900 9338 1528 1197 1184 3909 3786 1643 1 ! 2005 ! 7900 9337 1661 1282 1261 4204 3786 1347 1 1 2006 I 8200 9692 1794 1370 1336 4500 3786 1407 I 1 2007 ! 8200 9692 1924 1453 1401 4778 3786 1128 I PR E S E N T V A L U E A T : 13 p.cent .................... T o t a I P r o g r a m m e uS S/GCal 24.57 28.71 26.33 20.64 25.23 27.13 22.07 US $/MMOTU 6.19 7.24 6.63 5.20 6.36 6.84 5.56 Mill.USS 8875 1270 1009 881 3161 2725 2990 Billion M3 32.83 4.02 3.49 3.88 11.39 9.13 12.31 C o n t i n u a t i o n o f p r e s e n t s i t u a t i o n US S/GCal 17.65 17.89 19.05 15.58 17.38 17.71 US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46 Mill.US$ 3139 194 180 184 558 2581 Billion M3 16.17 0.99 0.86 1.07 2.92 13.25 I n c r e m e n t a l b a s i s s t a r t i n g i n 1 9 9 0 US $/GCal 31.29 32.24 28.70 22.57 27.93 27.13 n.m. US $/MMBTU 7.89 8.12 7.23 5.69 7.04 6.84 n.m. Mill.US$ 5735 1076 829 697 2602 2725 408 Billior. M3 16.66 3.03 2.63 2.81 8.47 9.13 -0.94 ................................................................................... P R E S E N T V A L U E A T : 8 p.cent .................... T o t a I P r o g r a m m e US $/GCal 23.52 29.27 26.80 21.04 25.77 22.23 22.24 US S/MMBTU 5.93 7.38 6.75 5.30 6.49 5.60 5.61 Mill.USS 12314 2088 1626 1391 5105 3628 4112 Billion M3 49.65 6.48 5.51 6.01 18.01 14.84 11.82 C o n t i n u a t i o n o f p r e s e n t s i t u a t i o n US S/GCal 17.75 19.40 19.05 15.58 18.04 17.71 US S/MMBTU 4.47 4.89 4.80 3.93 4.55 4.46 Mill.USS 4327 238 164 161 563 3763 Billion M3 22.16 1.12 0.78 0.94 2.84 19.32 I n c r e m e r t a 1 b a s i s s t a r t i n g i n 1 9 9 0 US $/GCal 28.40 32.27 28.91 22.81 28.16 22.23 n.m. US $/MMBTU 7.16 8.13 7.28 5.75 7.10 5.60 n.m. Mili-USS 8591 1822 1379 1139 4340 3628 619 Billion M3 27.50 5.13 4.34 4.54 14.01 14.84 -1.35 ........................................................................... (I) Gas supplied to Steam power plants is the volume of gas remaining after meetin the needs of non power demand for the whole Country, and the needs of of Contined Cycle plants considered as priority gas consumers. -138 - Page 4 of 5 K Y O N G I N / CHUNG CHO NG/ Y ONG NAN A R E A S c e n a r i o C 1. N A T U R A L G A S S U P P L Y / D E N A N D P R O G R A M --------------- ---------------------- ---------------------------- I I LNG SUPPLY I DEMAND Million 13/Year I TOTAL I POWER DEKAND I I I I I I (1) I I I K.Tons Mill.M3 IHouseh Cozmrc. Industry INON POWER ICorb Cyc Steam PI 1 1988 I 1926 2277 97 56 59 212 2065 I I 1989 I 2000 2364 144 125 157 427 1937 1 I 1990 I 2000 2364 180 169 210 559 1805 I I 1991 I 2000 2364 216 212 265 692 1672 I 1 1992 I 2500 2955 252 253 320 825 384 1746 I 1 1993 I 3000 3546 313 307 395 1015 945 1586 I I 1994 I 3500 4137 358 342 430 1130 1480 1527 I 1 1995 I 4000 4727 409 381 469 1259 1480 1989 I I 1996 I 5000 5909 571 528 636 1735 2172 2003 1 I 1997 I 5000 5910 653 590 692 1934 2172 1804 I I 1998 I 6000 7092 749 668 741 2158 2940 1994 I I 1999 I 7000 8274 862 749 802 2413 3325 2537 I I 2000 I 7000 8274 989 836 875 2700 3325 2250 1 I 2001 I 7000 8274 1128 933 965 3026 3325 1923 I I 2002 I 8500 10047 1259 1023 1036 3318 4093 2635 I I 2003 I 8500 10047 1393 1110 1111 3614 4093 2340 I I 2004 I 9500 11229 1528 1197 1184 3909 4862 2458 I I 2005 I 9500 11229 1661 1282 1261 4204 4862 2163 I I 2006 110000 11820 1794 1370 1336 4500 4862 2458 I I 2007 110000 11820 1924 1453 1401 4778 4862 2179 I P R E S E N T V A L U E A T : 13 p.cent .................... T o t a l P r o g r a m m e US S/GCal 24.81 28.71 26.33 20.64 25.23 27.13 22.29 US S/MMBTU 6.25 7.24 6.63 5.20 6.36 6.84 5.62 Mill.US$ 9913 1270 1009 881 3161 2725 3200 Billion H3 36.32 4.02 3.49 3.88 11.39 9.13 13.05 C o n t i n u a t i o n o f p r e s e n t s i t u a t i o n US $/GCal 17.65 17.89 19.05 15.58 17.38 17.71 US $/M8TU 4.45 4.51 4.80 3.93 4.38 4.46 Mill.USS 3139 194 180 184 558 2581 . Billion M3 16.17 0.99 0.86 1.07 2.92 13.25 I n c r e m e n ta l b a s i s s t a r t i n g i n 1 9 9 0 US $/GCal 30.56 32.24 28.10 22.57 27.93 27.18 n.m. US S/MMBTU 7.70 8.12 7.23 5.69 7.04 6.85 n.m. Mill.USS 6774 1076 829 697 2602 3553 619 . Billion M3 20.15 3.03 2.63 2.81 8.47 11.88 -0.20 . P R E S E N T V A L U E A T : 8 p.cent .................... T o t a I P r o ara m m e US S/GCal 23.48 2.a27 26.80 21.04 25.77 22.23 22.52 . US $/MMBTU 5.92 7.38 6.75 5.30 6.49 5.60 5.67 Mill.USS 13789 2088 1626 1391 5105 3628 4551 Billion M3 55.90 6.48 5.51 6.01 18.01 14.84 11.82 C o n t i n u a t i o n o f p r e s e n t s i t u a t i o n US S/GCal 17.75 19.40 19.05 15.58 18.04 17.71 US $/MIBTU 4.47 4.89 4.80 3.93 4.55 4.46 Mill.USS 4327 238 164 161 563 3763 Billion M3 22.16 1.12 0.78 0.94 2.84 19.32 I n c r e m e n ta l b a s i s s t a r t i n g i n 1 9 9 0 US $/GCal 27.43 32.27 28.91 22.81 28.16 22.27 n.m. US $/MMBTU 6.91 8.13 7.28 5.75 7.10 5.61 n.m. Mill.USS 10184 1822 1379 1139 4340 4781 1063 Billion M3 33.75 5.13 4.34 4.54 14.01 19.52 0.22 .............................................................................. (1) Gas supplied to Steam power plants is the volume of gas reraining after meetin the needs of 'non power demand' for the whole Country. and the needs uf of Combined Cycle plants considered as priority gas consumers. 10 Page 5 of 5 - 139 - K Y O N G I N / CHUNGC H O N G / Y O N G NAN A R E A S c e n a r i o 0 . N A T U R A L G A S S U P P L Y / D E N A N D P R O G R A M I I LNG SUPPLY I DEMAND Nillior. M3/Year I TOTAL I POWER DEMAND I I I I I I (1) I I I K.Tons Mill.M3 IHouseh Coim.rc. Industry INON POWER IComb Cyc Steam Pi I I I I II I 1988 I 1926 2277 97 56 59 212 2065 1 I 1989 I 2000 2364 144 125 157 427 1937 I 1 1990 I 2000 2364 180 169 210 559 1805 1 11991 1 2000 2364 216 212 265 692 1672 I I 1992 i 2500 2955 252 253 320 825 384 1746 I 11993 1 3000 3546 313 307 395 1015 945 1586 I I 1994 I 3500 4137 358 342 430 1130 1480 1527 I 11995 I 4000 4727 409 381 469 1259 1480 1989 I 11996 1 4500 5319 593 550 681 1825 1480 2015 I 11997 I 5000 5910 684 620 749 2053 1480 2378 I 11998 I 5500 6500 793 710 813 2317 1864 2320 I 11999 I 6000 7092 927 810 887 2624 2248 2219 I I 2000 I 6000 7093 1077 916 987 2979 2248 1865 I 1 2001 1 6400 7565 1246 1037 1114 3398 2248 1919 1 I 2002 I 7000 8274 1396 1142 1207 3746 3017 1511 I I 2003 I 7400 8746 1550 1243 1305 4098 3017 1631 I I 2004 I 8400 9928 1706 1344 1400 4450 3786 1693 1 I 2005 I 8400 9929 1860 1443 1501 4804 3786 1339 1 I 2006 I 8900 10519 2014 1544 1598 5156 3786 1578 I 12007 1 8900 10520 2165 1641 1686 5491 3786 1243 I P R E S E N T V A L U E A T : 13 p.cent .................... T o t a l P r o g r a m m e US $/GCal 24.62 28.82 26.43 20.76 25.31 27.13 22.09 US $/MNBTU 6.20 7.26 6.66 5.23 6.38 6.84 5.57 Mill.US$ 9143 1361 1082 968 3411 2725 3007 Billion M3 33.76 4.29 3.72 4.24 12.25 9.13 12.38 C o n t i n u a t i o n o f p r e s e n t s i t u a t i o n US $/GCal 17.65 17.89 19.05 15.58 17.38 17.71 US S/HMBTU 4.45 4.51 4.80 3.93 4.38 4.46 Nill.US$ 3139 194 180 184 558 2581 Billion N3 16.17 0.99 0.86 1.07 2.92 13.25 I n c r e m e n ta l b a s is s t a r t i n g i n 1 9 9 0 US S/GCal 31.03 32.09 28.65 22.52 27.79 27.13 n.m. US $/MMBTU 7.82 8.09 7.22 5.68 7.00 6.84 n.m. Mill.US$ 6003 1167 902 784 2853 2725 426 Billion M3 17.59 3.31 2.86 3.17 9.33 9.13 -0.87 ................................................................................... P R E S E N T V A L U E A T : 8 p.cent .................... T o t a l P r o r a m m e US $/GCal 23.61 29.36 26.90 21.16 25.83 22.23 22.27 US $/MTBTU 5.95 7.40 6.78 5.33 6.51 5.60 5.61 Mill.US$ 12774 2257 1759 1550 5567 3628 4147 Billion M3 51.37 6.99 5.94 6.66 19.59 14.84 11.82 C o n t i n u a t i o n o f p r e s e n t s i t u a t i o n US $/GCal 17.75 19.40 19.05 15.58 18.04 17.71 US $/MMBTU 4.47 4.89 4.80 3.93 4.55 4.46 Nill.US$ 4327 238 164 161 563 3763 Billion M3 22.16 1.12 0.78 0.94 2.84 19.32 I n c r e m e n ta I b a s i s s t a r t i n g i n 1 9 9 0 US $/GCal 28.28 32.11 28.83 22.74 27.99 22.23 n.m. US t/HMBTU 7.13 8.09 7.27 5.73 7.05 5.60 n.m. Mill.USS 9088 1991 1513 1298 4802 3628 654 Billion H3 29.21 5.64 4.77 5.19 15.59 14.84 -1.22 ............................................................................... (1) Gas supplied to Steam power plants is the volume of gas remaining after metin the needs of 'non power demand' for the whole Country, and the needs of of Combined Cycle plants considered as priority gas consuners. - 140 - A 10 KOREA GAS UTILIZATION STUDY Estimt, of Investment Cost AVERAGE COST OF I NFRASTRUCTURE Scenar io .A . :KYONGI N AREA I I C A P I T A L I N V E S T M E N T .OPERATION COST I I IL DO TERMINAL . PYONG PIPELINES DISTRIB-. I 13 Tanks 1 Tank . TAEK UTION .Terminal Network I I I- _I I Imillion US $ (1) .million US S (1) .million S/Y i I 1989 I I 1990I . 6.5 70.14. 2.4 I I 1991 I 9.9 . 19.3 22.0 70.50 . 4.8 I I 1992 1 34.1 . 27.4 44.1 70.54 . 7.2 I I 1993 I 60.8 17.1 44.0 62.53 . 1.0 9.3 I I 1994 I 103.7 6.5 49.47 . 1.4 11.0 I I 1995 I 108.0 52.06 . 2.0 12.7 I I 1996 I 77.8 19.7 58.61 . 8.4 14.7 I I 1997 I 50.0 61.86 . 8.4 16.8 1 I 1998 I 6.3 61.63 . 9.6 18.9 1 I 1999 1 72.07 . 9.6 21.4 1 I 2000 I 76.71 . 9.6 24.0 I I 2001 I 7.3 82.17 . 9.6 26.8 I I 2002 I 22.1 71.06 . 9.6 29.2 I I 2003 I 39.4 72.18 . 9.6 31.6 I I 2004 1 46.4 71.91 . 9.6 34.1 I I 2005 I 26.4 71.93 . 9.6 36.5 I I 2006 I 4.5 72.19 . 11.0 39.0 I I 2007 I 65.84 . 12.1 41.2 I I I T-O TOTAL C O S T . G A S S U P PPL Y I I (n c r e m e n t a I ) (I n c r e m e n t a l ) I I ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I I Imilon US $ M1i1.M3/Y BCF /Y BCF I 1 1989I . . 1 1990 1 76.66 . 76.66. 0 I 1991 1 121.65 . 121.65 . -1 I I 1992 I 176.18 . 176.18. 591 20.9 21 I 1 1993 I 184.44 10.30 . 194.74 1110 39.2 60 I I 1994 1159.68 12.38 172.06 1655 58.4 119 I I 1995 i 160.04 14.74 . 174.78 2245 79.3 198 I I 1996 I 156.13 23.13 . 179.26 2364 83.5 281 I 1 1997 I 111.82 25.24 . 137.06 2837 100.1 381 I i 1998 I 67.89 28.53 . 96.42 3310 116.8 498 1 1 1999 1 72.07 30.98 . 103.05 3664 129.3 628 I 1 2000 I '.71 33.58. 110.29 3487 123.1 751 I I 2001 I 89.46 36.37 . 125.83 3665 129.4 880 I I 2002 I 93.17 38.79 131.96 4078 144.0 1024 I I 2003 I 111.60 41.24 . 152.84 4432 156.4 1180 i 1 2004 I 118.36 43.68 . 162.04 5142 181.5 1362 I I 2005 I 98.32 46.12 . 144.44 5142 181.5 1543 1 I 2006 I 76.73 49.97 . 126.70 5260 185.7 1729 I I 2007 I 65.84 53.31 . 119.15 5260 185.7 1915 I ---- _ I (1)e x c u d i n g t a x e s o n i m p o r t e d m a t e r i a l (27.5 % of material cost) I I I DISCOUNT RATE % I 0 8 11 . 13 15 1 - _ .I I CUMULATED D C F M.$ I 2505.1 1315.3 1081.4 . 959.9 859.0 I I GAS DISCOUNT. VOL BCF I 1915 773 574 . 477 399 1 - - __I I A.I.C. (S/ MM8TU) I 1.06 1.38 1.52 1.63 1.74 I I (S/ GCal) I 4.21 5.48 6.03 6.47 6.90 I I A.I.C. (S/ MCF) I 1.31 1.70 1.88 2.01 2.15 I I (W o n / n13) I 30.5 39.8 43.8 47.0 50.1 I --- - GAS LHV BTU /CFT 1236 Exchange rate- KCal/M3 11000 660 Won /US S 11 - 141 - Page 2 of 10 C O S T O F I N F R A S T R U C T U R E S c e n a ri o . A . : K Y O N G I N A R E A I n c l u d i n g T a x e s (1) t I C A P I T A L I N V E S T M E N E N T .OPERATION COST I I I 1L DO TERMINAL 3 rd . PYONG PIPELINES OISTRIB-. I 13 Tanks 1 Tank 1 Termin. TAEK UTION .Terminal Network I I__ _ _I- _I I Imillion US $ .million US $ .million S/Y I 1 1989 1 I 19901 . 7.6 70.14. 2.4 1 I 1991 1 11.5 . 22.5 23.7 70.50 . 4.8 1 11992 1 39.8 . 32.0 47.5 70.54 . 7.2 1 11993 1 70.9 20.0 47.4 62.53 . 1.0 9.3 1 1 1994 1 121.0 7.6 49.47 . 1.4 11.0 I 1 1995 1 126.0 52.06 . 2.0 12.7 1 11996 1 90.8 23.0 58.61 . 8.4 14.7 1 1 1997 1 58.3 61.86 . 8.4 16.8 1 11998 1 7.3 61.63 . 9.6 18.9 1 1 1999 1 72.07 . 9.6 21.4 1 12000 1 76.71 . 9.6 24.0 1 1 2001 1 8.5 82.17 . 9.6 26.8 1 1 2002 1 25.8 71.06 . 9.6 29.2 1 1 2003 1 46.0 72.18 . 9.6 31.6 1 1 2004 1 54.2 71.91 . 9.6 34.1 1 1 2005 1 30.8 71.93 . 9.6 36.5 1 I 2006 1 5.3 72.19 . 11.0 39.0 1 1 2007 1 65.84 . 12.1 41.2 1 ------ (1) Breakdown of TERMINAL cost Material 52 p.cent Construction 31 p.cent Engineering/ 17 p.cent Other PIPELINE cost Material 26 p.cent Construction 56 p.cent Engineering/ 18 p.cent Other Taxes are set at 27.5 p.cent of imported material cost including 22.5 % of customs duty. S U M M A R Y O F I N V E S T M E N T S C H E D U L E I I T o t a l T e r m i n a l s I I P e r i o d I . PYONG IL 00 3 RD . PIPE OISTRIB- I I . TAFK TERMINAL. LINES UTION I I .m i ll i o n U SS I I ~ ~ ~~I . .I I I . .I 1 9 9 0 - 1 9 9 3 1 596.6. 82.1 122.2 . 118.6 273.7 1 I I . .I 1 I ..I I1 9 9 4 - 1 9 9 7 1 648.7. 7.6 419.1 . 222.0 1 I I . .I I I . .I I1 9 9 8 - 2 0 0 1 1 308.4. 8.5 7.3 . 292.6 1 I I . .I I I . .I 12 0 0 2 - 2 0 0 6 1 449.2. 162.1 . 287.1 1 I I . .I I I . .I I T O T A L 1 2002.9 . 260.3 548.6 . 118.6 1075.4 1 I I . .-I II Annex 1 1 - 142 - Page 3 of 10 A V E R A G E C O S T O F I N F k A S T R U C T U R E S c e n a r i o 8 : K Y O N G I + C H U N G C H N G REA I I C A P I T A L I N V E S T H E N T .OPERATION COST i I I IL DO TERMINAL 3 rd . PYONG PIPELINES DISTRIB-. I 13 Tanks 1 Tank I Termin. TAEK UTION .Terminal Network I I I __--- ----- ----- ----- ----- -- --- I Imillion US $ (1) .million US $ (1) .million $/Y I I 1989 I 11990I . 6.5 70.14. 2.4 1 I 1991 I 9.9 . 19.3 18.6 22.0 70.50 . 4.8 I I 1992 I 34.1 . 27.4 37.5 44.1 70.54 . 7.2 I I 1993 I 60.8 17.1 37.5 44.0 90.05 . 1.0 9.4 I I 1994 1 103.7 6.5 54.78 . 1.4 11.3 I I 1995 I 108.0 61.00 . 2.0 13.3 I I 1996 I 77.8 19.7 5.0 70.56 . 8.4 15.7 I I 1997 I 50.0 65.70 . 8.4 17.9 I I 1998 I 6.3 73.15 . 9.6 20.4 I 1 1999 I 80.52 . 9.6 23.1 I I 2000 I 89.28 . 9.6 26.1 I I 2001 I 7.3 98.97 . 9.6 29.4 I I 2002 I 22.1 86.72 . 9.6 32.3 1 I 2003 I 39.4 87.72 . 9.6 35.3 I I 2004 I 46.4 88.53 . 9.6 38.3 I I 2005 I 26.4 88.50 . 9.6 41.3 I 1 2006 I 4.5 87.79 . 11.0 44.2 1 1 2007 I 80.60 . 12.1 46.9 1 I I T O T A L C O S T . G A S S U P P L Y I I I (I n c r e ni e n t a 1 ) (I n c r e m e n t a I ) I I ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I I Imilton US $ Mi11.M3/Y BCF /Y 8CF I 11989 I 11990 1 76.66 . 76.66. 0 I 11991 1140.22 . 140.22 . -1 I 11992 I213.69 . 213.69 . 591 20.9 21 1 I 1993 I 249.47 10.41 . 259.88 1182 41.7 63 I I 1994 I 164.99 12.65 177.64 1773 62.6 125 I 11995 I 168.98 15.31 . 184.29 2364 83.5 209 I 11996 1173.10 24.09 . 197.19 2542 89.7 298 I I 1997 I 115.66 26.30 . 141.96 3074 108.5 407 I I 1998 I 79.40 29.96 . 109.36 3545 125.2 532 I I 1999 I 80.52 32.67 . 113.19 4019 141.9 674 I I 2000 I 89.28 35.68 . 124.96 4019 141.9 816 I I 2001 I 106.26 39.02 . 145.28 4078 144.0 960 I I 2302 I 108.83 41.94 150.77 4492 158.6 1119 1 I 2003 I 127.14 44.89 . 172.03 4906 173.2 1292 I I 2004 I 134.98 47.87 . 182.85 5910 208.6 1500 I I 2005 I 114.90 50.86 . 165.76 5910 208.6 1709 I I 2006 I 92.33 55.21 . 147.54 6029 212.8 1922 I I 2007 1 80.60 59.03 . 139.63 6028 212.8 2135 I (1)e x c u d i n g t a x e s o n i m p o r t e d m a t e r i a 1 (27.5 % of material cost) I OISCOUNT RATE % I 0 8 11 . 13 15 1 I CUMULATED D C F M.S I 2842.9 1493.9 1229.2 . 1091.6 977.4 I I GAS DISCOUNT. VOL BCF I 2135 855 632 . 524 437 i I A.I.C. (S/ MM8TU) I 1.08 1.41 1.57 1.69 1.81 I I (SI GCal) I 4.29 5.60 6.23 6.71 7.18 I I A.I.C. (S/ MCF) I 1.33 1.75 1.94 2.09 2.24 I I (W o n / M3) I 31.1 40.6 45.2 48.7 52.1 1 I--- - -- - -- - -- -- - -- - -- - -- -- - -- - -- - -- -- - -- - -- - -- GAS LHV BTU /CFT 1236 Exchange rate- KCal/M3 11000 660 Won /US $ 11 - 143- Page 4 of 10 C O S T O F I N F R A S T R U C T U R E S c e n a r i o B : K Y O N G I N * C H U N G C H O N G A R E A I n c I u d I n g T a x e s (1) I I I C A P I T A L I N V E S T M E N T .OPERATION COST I I I IL DO TERMINAL 3 rd . PYONG PIPELINES OISTRIB-. i I 13 Tanks I Tank 1 Termin. TAEK UTION .Terminal Network I I Ilmillion US $ .million US $ .million $/Y I 1 1989 1 I 11990 1 . 7.6 70.14. 2.4 1 I 1991 1 11.5 . 22.5 20.0 23.7 70.50 . 4.8 1 1 1992 1 39.8 . 32.0 40.4 47.5 70.54 . 7.2 I I 1993 1 70.9 20.0 40.4 47.4 90.05 . 1.0 9.4 1 1 1994 1 121.0 7.6 54.78 . 1.4 11.3 1 1 1995 1 126.0 61.00 . 2.0 13.3 1 1 1996 1 90.8 23.0 5.4 70.56 . 8.4 15.7 I I 1997 1 58.3 65.70 . 8.4 17.9 I I 1998 I 7.3 73.15 . 9.6 20.4 I I 1999 I 80.52 . 9.6 23.1 I 1 2000 I 89.28 . 9.6 26.1 I I 2001 I 8.5 98.97 . 9.6 29.4 I 1 2002 I 25.8 86.72 . 9.6 32.3 I I 2003 I 46.0 87.72 . 9.6 35.3 I 1 2004 I 54.2 88.53 . 9.6 38.3 I I 2005 I 30.8 88.50 . 9.6 41.3 I 12006 I 5.3 87.79 . 11.0 44.2 I I 2007 1 80.60 . 12.1 46.9 I -- (1) Breakdown of TERMINAL cost Material 52 p.cent Construction 31 p.cent Engineering/ 17 p.cent Other PIPELINE cost :Material 26 p.cent Construction 56 p.cent Engineering/ 18 p.cent Other Taxes are set at 27.5 p.cent of imported mnterial cost Including 22.5 % of customs duty. S U M M A R Y O F I N V E S T M E N T S C H E D U L E I ~~~~~~I T a t a I T e r m I n a I s I I P e r i o d I .PYONG IL DO 3 RD . PIPE DISTRIB- I I I . TAEK TERMINAL. LINES UTION I I I .mi1l1i on U SS .I I I m. I I ~ ~ ~~I . .I 1 9 9 0 - 1 9 9 3 I 724.9. 82.1 122.2 . 219.4 301.2I I I . .I I I . .I 19 9 4 - 1 9 9 7 I 684.1. 7.6 419.1 . 5.4 252.0 1 I I . I I I . .I I1 9 9 8 - 2 0 0 1 I 357.7. 8.5 7.3 . 341.9 1 I I . .I I I . .I 12 0 0 2 - 2 0 0 6 I 513.6. 162.1 . 351.5 1 I I..I I I..I I T O T A L I 2280.4. 260.3 548.6 . 224.8 1246.7 1 I I . . I I ---- I - 144 - Annex 11 Page 5 of 10 AVERAGE COSt OF I NFRASTRUCTURE Scena r io C : K YONG I N/ CHUNGCHONG/ YONGNAM I I C A P I T A L I N V E S T H E N T .OPERATION COST I I I IL 00 TERMINAL 3 rd . PYONG PIPE DISTRIB-. I IPort/Sit Terminal Termin. TAEK LINES UTION .Terminal Network I I- I I Imillion US S (1) .million US $ (1) .miliion S/Y I I 1989 I I I 1990 I 9.9 . 6.5 70.14 . 2.4 I I 1991 I 34.1 . 19.3 40.7 70.50 . 4.8 I I 1992 I 60.8 . 27.4 81.6 70.54 . 7.2 I I 1993 1 103.7 17.1 130.8 90.05 . 1.0 9.4 I 1 1994 I 108.0 6.5 114.7 54.90 . 1.9 11.3 I I 1995 I 77.8 19.7 114.7 60.89 . 2.5 13.3 1 1 1996 I 50.0 5.0 226.16 . 10.4 20.9 1 I 1997 I 6.3 7.7 94.74 . 10.4 24.1 1 I 1998 I 106.17 . 11.6 27.7 I I 1999 I 7.3 121.25 . 11.6 31.8 1 I 2000 I 22.1 136.27 . 11.6 36.4 I I 2001 I 39.4 154.86 . 11.6 41.6 I I 2002 I 46.4 138.69 . 11.6 46.3 I 1 2003 I 26.4 140.42 . 11.6 51.0 I I 2004 1 4.5 140.31 . 13.0 55.7 1 I 2005 I 140.22 . 14.1 60.4 1 I 2006 I 140.55 . 14.1 65.2 I I 2007 I 132.2? . 14.1 69.6 I I I T O T A L C O S T . G A S S U P P L I I I (I n c r e m e n t a ) (I n c r e m e n t a l ) I I ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I I - ____ I Imilion US $ Mill.M3/Y BCF /Y BCF I I 1989 1 . .I i 1990 1 86.51 . 86.51. -O I 1991 I 164.56 . 164.56 . -0 I 1992 I 240.34 . 240.34 . 591 20.9 21 I I 1993 I 3'1.71 10.41 . 352.12 1182 41.7 63 I I 1994 I 284.06 13.16 297.22 1773 62.6 125 I I 1995 I 273.08 15.81 . 288.89 2363 83.4 209 I I 1996 I 281.14 31.33 . 312.47 2837 100.1 309 1 I 1997 I 108.71 34.52 . 143.23 3428 121.0 430 I I 1998 I 106.17 39.29 . 145.46 4019 141.9 572 I I 1999 I 128.54 43.38 . 171.92 4491 158.5 730 I 1 2000 I 158.38 47.97 . 206.35 4492 158.6 889 I 1 2001 I 194.28 53.19 . 247.47 4847 171.1 1060 I I 2002 I 185.14 57.86 243.00 5319 187.8 1248 I I 2003 t 166.82 62.59 . 229.41 5909 208.6 1456 I I 2004 I 144.85 68.71 . 213.56 6973 246.2 1702 I I 2005 I 140.22 74.54 . 214.76 6973 246.2 1949 I I 2006 I 140.55 79.27 . 219.82 7328 258.7 2207 I I 2007 I 132.22 83.72 . 215.94 7328 258.7 2466 I --- __I (I) e x c I u d i n g t a x e s o n i m p o r t e d m a t e r i a 1 (27.5 % of material cost) I DISCOUNT RATE % I 0 8 11 . 13 15 1 I CUMULATED D C F M.S I 3993.0 2064.9 1687.5 . 1491.7 1329.4 1 I GAS DISCOUNT. VOL BCF I 2466 971 714 . 588 489 i ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~I I A.S.C. (S/ MMBTJ) I 1.31 1.72 1.91 2.05 2.20 1 (SI GCal) I 5.20 6.83 7.58 8.13 8.73 1 I A.I.C. (S/MCF) I 1.62 2.13 2.36 2.54 2.72 1 I (W o n / M3) 1 37.7 49.6 55.0 59.1 63.4 1 GAS LHV BTU /CFT 1236 Exchange rate- KCallM3 11000 660 Won /S S GAS LHV BTU /CFT 1236 Exchange rate- KCal/M3 11000 660 Won /US $ 0 0.08 0.11 0.13 0.15 - 145 - Page 6 of 10 C O S T O F I N F R A S T R U C T U R E S c e n a r i o C : K Y O N G I N / C H U N G C N O N G / Y O N G N A M I n c l u d i n g T a x e s (1) I I C A P I T A L I N V E S T M E Nt .OPERATION COST I I I IL DO TERMINAL 3 rd . PYONG PIPE DISTRIB-. I I 53 Tanks I Tank 1 Termin. TAEK LINES UTION .Terminal Network I S -.._I-- Imillion US $ .million US $ .million S/Y I 11989 1 I I 1990 1 11.5 . 7.6 70.14 . 2.4 I 11991 1 39.8 . 22.5 43.8 70.50 . 4.8 5 1 1992 1 70.9 . 32.0 87.9 70.54 . 7.2 1 I1993 I 121.0 20.0 140.9 90.05 . 1.0 9.4 I I1994 1 126.0 7.6 123.5 54.90 . 1.9 11.3 1 11995 I 90.8 23.0 123.5 60.89 . 2.5 13.3 I I1996 I 58.3 5.4 226.16 . 10.4 £0.9 I I1997 1 7.3 8.3 94.74 . 10.4 24.1 I 1 1998 1 106.17 . 11.6 27.7 1 I 1999 1 8.5 121.25 . 11.6 31.8 1 I 2000 I 25.8 136.27 . 11.6 36.4 I 1 2001 I 46.0 154.86 . 11.6 41.6 1 1 2002 I 54.2 138.69 . V.6 46.3 I I 2003 I 30.8 140.42 . 11.6 51.0 I I 2004 I 5.3 140.31 . 13.0 55.7 I 1 2005 1 140.22 . 14.1 60.4 1 1 2006 1 140.55 . 14.1 65.2 I 1 2007 I 132.22 . 14.1 69.6 I ---------- - (1) Breakdown of TERMINAL cost :Material 52 p.cent Construction 31 p.cent Engineering/ 17 p.cent Other PIPELINE cost : Material 26 p.cent Construction 56 p.cent Engineering/ 18 p.cent Other Taxes are set at 27.5 p.cent of inported material cost including 22.5 % of customs duty. S U M M A R Y O F I N V E S T M E N T S C H E D U L E I I T o t a l T e r m i n a l s I P e r i o d I . PYONG IL DO 3 RD . PIPE DISTRIB- I I I . TAEK TERMINAL. LINES UTION I I I .m l l i o n U S $ . I 1 9 9 0 - 1 9 9 3 I 899.1. 82.1 243.2 . 272.6 301.2 5 I I . .5 I1 9 9 4 - 1 9 9 7 I 1010.4. 7.6 305.4 . 260.7 436.7 I I I . I I I .~~~ . I I1 9 9 8 - 2 0 0 1 1 598.9. 80.3 . 518.6 1 I I . . I I..I 52 0 0 2 - 2 0 0 6 1 649.9. 90.3 . 559.6 5 I I . . I T O T A L I 3158.3. 260.3 548.6 . 533.3 1816.1 I I I . . I Annex 1 1 - 146 - Page 7 of 10 AVERAGE COST OF I NFRASTRUCTURE Scenario0 C1. :KY0NGIN/ CHIUNGCHONG/YON6NAM I I C A P I T A L I N V E S T 1 E N T .OPERATION COST I I I IL 00 TERMINAL 3 rd . PYONG PIPE DISTRIB-. I I IPort/Sit Terminal Termin. TAEK LINES UTION .Terminal Network I I I-- - - - - - - - - - - - - - - -I I Imillion US $ (1) .million US S (1) .million $/Y I I 1989 I I 1990 I 9.9 . 6.5 70.14 . 2.4 I I 1991 1 34.1 . 19.3 40.7 70.50 . 4.8 1 1 1992 I 60.8 . 27.4 81.6 70.54 . 7.2 I 1 1993 I 103.7 17.1 130.8 90.05 . 1.0 9.4 I I 1994 I 108.0 6.5 114.7 54.90 . 1.9 11.3 I I 1995 I 77.8 19.7 114.7 60.89 . 2.5 13.3 I I 1996 1 50.0 5.0 226.16 . 10.4 20.9 1 1 1997 I 6.3 7.7 94.74 . 10.4 24.1 1 1 1998 1 106.17 . 11.6 27.7 I 11999 1 13.8 121.25 11.6 31.8 1 1 2000 I 41.4 136.27 . 11.6 36.4 I 1 2001 1 66.8 154.86 . 11.6 41.6 1 12002 1 63.6 138.69 . 11.6 46.3 1 1 2003 I 32.9 140.42 . 11.6 51.0 I I 2004 1 4.5 140.31 . 13.0 55.7 1 12005 1 140.22 . 15.4 60.4 I I 2006 I 140.55 . 15.4 65.2 I ! 2007 I 132.22 . 15.4 69.6 I ! ----------------------------------------------------------------------- I I TOTAL COST . GAS SUPPLY I I i (I n c r e m e n t a 1) (I n c r e m e n t a l ) I I ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I !I------ I------------------------------------____-----____ _______I____ ___ __ I Imilion US S Mill.H3/Y BCF /Y BCF I !I------I--------------------------------------------------_-_-_________-__- _ !1989I . . 11990 1 86.51 .86.51. -0 t I1991 1 164.56 164.56. -0 I ! 1992 I 240.34 240.34 . 591 20.9 21 I ! 1993 I 341.71 10.41 . 352.12 1182 41.7 63 I 11994 I 284.06 13.16 297.22 1773 62.A 125 I I 1995 I 273.08 15.81 . 288.89 2363 83.4 209 I I 1996 I 281.14 31.33 . 3!2.47 3545 125.1 334 1 I 1997 I 108.71 ;4.52 . 143.23 3546 125.2 459 1 I 1998 1 106.17 39.29 . 145.46 4728 166.9 626 i I 1999 I 135.05 43.38 . 178.43 5910 208.6 834 I I 2000 I 177.66 47.97 . 225.63 5910 208.6 1043 I I 2001 ! 221.70 53.19 . 274.89 5910 208.6 1252 I I 2002 I 202.28 57.86 260.14 7682 271.2 1523 I I 2003 1 173.33 62.59 . 235.92 7683 271.2 1794 I 12004 1 144.85 68.71 . 213.56 8865 312.9 2107 I I 2005 I 140.22 75.84 . 216.06 8865 312.9 2420 I I 2006 I 140.55 80.57 . 221.12 9456 333.8 2754 I I 2007 I 132.22 85.02 . 217.24 9456 333.8 3087 I (1)e x c u d i n g t a x e s o n i m p o r t e d m a t e r i a 1 (27.5 % of material cost) I_-- - -- - -- - -- - -- - -- - - -- - -- - -- - -- - -- - -- - - I DISCOUNT RATE % I 0 8 11 . 13 15 1 -- - - - - - - - - - - - - _ - - -_ - - - -_- I I CUMULATED D C F N.$ I 4073.8 2096.7 1710.3 . 1510.2 1344.4 I I GAS DISCOUNT. VOL BCF I 3087 1191 868 . 711 588 I I A.I.C. (S/ MM6TU) I 1.07 1.42 1.59 1.72 1.85 1 I (SI GCal) I 4.25 5.63 6.31 6.83 7.34 I I A.I.C. JS/ MCF) I 1.32 1.76 1.97 2.12 2.29 I I {M n / M3) 1 30.8 40.9 45.8 49.6 53.3 I GAS LHV 8TU /CFT 1236 Exchange rate- KCal/H3 11000 660 Won /US S Annex 11 - 147 - Page 8 of 10 CoST O F I N F R A S T R U C T U R E S c e n a ri5 o C 1. : K Y O N G I N / C H U N G C H O N G / Y O N G N A H I n c I u d i n 9 T a x e s (1) I I I C A P I T A L I N V E S T M E N T .OPERATION COST I I I IL DO TERnINAL 3 rd . PYONG PIPE OISTRIB-. I I 13 Tanks I Tank 1 Termin. TAEK LINES UTION .Terminal Network I I Imillion US $ .million US S .million S/Y I I 1989 . I I 1990 I 11.5 . 7.6 70.14 . 2.4 I I 1991 I 39.8 . 22.5 43.8 70.50 . 4.8 I I 1992 I 70.9 . 32.0 87.9 70.54 . 7.2 I I 1993 I 121.0 20.0 140.9 90.05 . 1.0 9.4 I 11994 I 126.0 7.6 123.5 54.90 . 1.9 11.3 1 11995 I 90.8 23.0 123.5 60.89 . 2.5 13.3 I I 1996 1 58.3 5.4 226.16 . 10.4 20.9 I I 1997 I 7.3 8.3 94.74 . 10.4 24.1 I I 1998 I 106.17 . 11.6 27.7 I 11999 I 16.1 121.25 . 11.6 31.8 I I 2000 I 48.3 136.27 . 11.6 36.4 I I 2001 1 78.0 154.86 . 11.6 41.6 I I 2002 I 74.2 138.69 . 11.6 46.3 I I 2003 I 38.4 140.42 . 11.6 51.0 I I 2004 I 5.3 140.31 . 13.0 55.7 I I 2005 I 140.22 . 15.4 60.4 I I 2006 I 140.55 . 15.4 65.2 I I 2007 I 132.22 . 15.4 69.6 I ----- (1) Breakdown of TERMINAL cost :Material 52 p.cent Construction 31 p.cent Engineering/ 17 p.cent Other PIPELINE cost : Material 26 p.cent Constructiun 56 p.cent Engineering/ 18 p.cent Other Taxes are set at 27.5 p.cent of iqorted material cost including 22.5 t of customs duty. S U M M A R Y O F I N V E S T M E N T S C H E D U L E I I T o t a I T e r m i n a sI I P e r i o d I .PYONG IL DO 3 RD . PIPE DISTRIB- I I I . TAEK TERMINAL. LINES UTION I I I .m i I i o n U S $ . I I I . .I I I . .I 1 9 9 0 - 1 9 9 3 1 899.1. 82.1 243.2 . 272.6 301.2 1 I I . .I I I . .I I1 9 9 4 - 1 9 9 7 I 1010.4. 7.6 305.4 . 260.7 436.7 1 I I . .I I I . .I I1 9 9 8 - 2 0 0 1 1 661.0. 142.4 . 518.6 1 I I . .I 12 0 0 2 - 2 0 0 6 1 677.5 117.9 559.6 1 I I . .I I I . .I I T O T A L I 3248.0 . 350.0 548.6 . 533.3 1816.1 1 I I .-- I I 11 - 148- Page 9 of 10 A V E R A G E C O S T O F I N F R A S T R U C T U R E K Y O N G I N / C H U N G C H O N G / Y O N G N A M / H O N A N S c e n a r i o D I I C A P I T A L I N V E S T M E N T .OPERATION COST I I I IL DO TERMINAL 3 rd . PYONG PIPE DISTRIB-. I I IPort/Sit Terminal Termin. TAEK LINES UTION .Terminal Network I I-- -- -- -- -- -- -- - -- -- -- -- -- -- -- - -- -- -- -- -- - -I I Imillion US $ (1) .million US $ (1) .million S/Y I I - _---_-_---------- --- 1 1989 1 I I 1990 1 9.9 . 6.5 70.14 . 2.4 1 11991 1 34.1 . 19.3 40.7 70.50 . 4.8 I I 1992 1 60.8 . 27.4 81.6 70.54 . 7.2 I 11993 1 103.7 17.1 156.8 90.05 . 1.0 9.4 1 1 1994 I 108.0 6.5 189.5 54.90 . 1.9 11.3 I I 1995 I 77.8 19.7 212.3 60.89 . 2.5 13.3 1 I 1996 1 50.0 50.5 268.88 . 11.1 22.4 ' 1 1997 1 6.3 7.7 108.26 . 11.7 26.0 1 1 1998 1 125.44 . 12.9 30.2 1 I 1999 1 7.3 146.02 . 12.9 35.2 1 I 2000 I 22.1 168.66 . 12.9 40.8 1 1 2001 1 39.4 198.74 . 12.9 47.5 1 12002 1 46.4 165.30 . 12.9 53.1 1 12003 I 26.4 167.55 . 12.9 58.7 1 1 2004 I 4.5 166.91 . 12.9 64.4 1 12005 I 168.15 . 15.4 70.0 1 1 2006 1 167.14 . 15.4 75.7 1 12007 1 159.36 . 15.4 81.0 1 _- -- -- -- -- -- -- -- - -- -- -- -- -- -- -- -- - -- -- -- -- -- -- -- - _ I------------------------------------------------------------------- I I T O T A L C O S T . G A S SU P P L Y I I (I n c r e m e n t a ) (I n c r e m e n t a l ) I I ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I I-------------------------------------------------------------------_I I Imilion US $ Mill.M3/Y BCF /Y BCF I ------I --- -- -- -- -- -- - 119891 . . I 11990 1 86.51 . 86.51. -0 11991 1164.56 .164.56 . -0 I 1 1992 1 240.34 . 240.34 . 591 20.9 21 1 1 1993 1 367.71 10.41 . 378.12 1182 41.7 63 1 I 1994 I 358.90 13.16 372.06 1773 62.6 125 I I 1995 I 370.67 15.81 . 386.48 2363 83.4 209 1 1 1996 1 369.35 33.47 . 402.82 2955 104.3 313 1 1 1997 1 122.22 37.71 . 159.93 3546 125.2 438 1 1 1998 I 125.44 43.14 . 168.58 4136 146.0 584 I I 1999 1 153.31 48.06 . 201.37 4728 166.9 751 1 1 2000 1 190.77 53.74 . 244.51 4728 166.9 918 1 1 2001 1238.16 60.43 . 298.59 5201 183.6 1102 1 1 2002 1 211.75 66.00 277.75 5910 208.6 1310 1 1 2003 1 193.94 71.64 . 265.58 6382 225.3 1535 1 1 2004 I 171.45 77.27 . 248.72 7564 267.0 1802 I 1 2005 1 168.15 85.43 . 253.58 7565 267.0 2069 1 1 2006 1 167.14 91.06 . 258.20 8155 287.9 2357 1 1 2007 I 159.36 96.43 . 255.79 8156 287.9 2645 1 ' --- _ _I _ (1) e x c I u d i n g t a x e s o n i m p o r t e d m a t e r i a 1 (27.5 % of material cost) I-- - - - - - - - - - - - I DISCOUNT RATE % I 0 8 11 . 13 151 I I I CUMULATED 0 C F M.$ I 4663.5 2387.9 1942.7 . 1711.9 1520.7 1 I GAS DISCOUNT. VOL BCF I 2645 1031 755 . 621 515 1 -- - - - - - - - - - - - - - - - - - - - - - I I A.I.C. (S/ MMBTU) I 1.43 1.87 2.08 2.23 2.39 1 I S/ GCal) I 5.67 7.42 8.25 8.85 9.48 1 I A.I.C. (S/ MCF) I 1.76 2.32 2.57 2.76 2.95 1 I (W o n / 143) 1 41.2 53.9 59.9 64.2 68.9 1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - GAS LHV BTU /CFT 1236 Exchange rate- KCal/M3 11000 660 Won /US S 11 - 149 - Page 10 of 10 KY ONG IN/ CHUNG CHO NG/ Y ONG NAM/ HO NAM S c e n a r i o 0 I n c I u d i n g T a x e s (1) I I C A P I T A L I N V E S T M E N T .OPERATION COST I I I IL 00 TERMINAL 3 rd . PYONG PIPE OISTRIB-. I 1 13 Tanks I Tank 1 Termin. TAEK LINES UTION .Terminal Network I I Imillion US $ .million US S million t/Y I 1 1989 1 ' 1990 1 11.5 . 7.6 70.14 . 2.4 1 I 1991 1 39.8 . 22.5 43.8 70.50 . 4.8 i 1 1992 1 70.9 . 32.0 87.9 70.54 . 7.2 1 1 1993 1 121.0 20.0 168.9 90.05 . 1.0 9.4 1 1 1994 1 126.0 7.6 204.1 54.90 . 1.9 11.3 1 1 1995 1 90.8 23.0 228.6 60.89 . 2.5 13.3 1 1 1996 1 58.3 54.4 268.88 . 11.1 22.4 1 1 1997 1 7.3 8.3 108.26 . 11.7 26.0 1 1 1998 1 125.44 . 12.9 30.2 1 I 1999 1 8.5 146.02 . 12.9 35.2 1 1 2000 1 25.8 168.66 . 12.9 40.8 1 1 2001 1 46.0 198.74 . 12.9 47.5 1 1 2002 1 54.2 165.30 . 12.9 53.1 1 1 2003 1 30.8 167.55 . 12.9 58.7 1 1 2004 1 5.3 166.91 . 12.9 64.4 1 1 2005 1 168.15 . 15.4 70.0 1 1 2006 1 167.14 . 15.4 75.7 1 1 2007 1 159.36 . 15.4 81.0 1 - - - - - - --- - - - - - - - - - - - (1) Breakdown of TERMINAL cost :Material 52 p.cent Construction 31 p.cent Engineering/ 17 p.cent Other PIPELINE cost : Material 26 p.cent Construction 56 p.cent Engineering/ 18 p.cent Other Taxes are set at 27.5 p.cent of imported material cost including 22.5 % of customs duty. S U M M A R Y O F I N V E S T M E N T S C H E D U L E I I T o t a I T e r m i n a Is I I P e r i o I . PYONG IL DO 3RO . PIPE DISTRIB- I I I . TAEK TERMINAL. LINES UTION I I .m i i o n U SS . I I~~~~~~~~~~~~~~ I I . .I I I . .I I 9 9 0 - I 9 9 3 1 927.1. 82.1 243.2 . 300.6 301.2! I I . .I I I . .I II 9 9 4 - 1 9 9 7 1 1301.3. 7.6 305.4 . 495.4 492.9 1 I ~ ~ ~~I . .I I I . .I I1 9 9 8 - 2 0 0 1 1 719.2. 80.3 . 638.9 1 I I..i I I . I 12 0 0 2 - 2 0 0 6 1 758.2. 90.3 . 667.9 1 I I I I..I I T O T A L 1 3705.8 . 260.3 548.6 . 796.0 2100.9 1 I I . .-I I _ ___ _ _I - 150 - Page 1 of 10 KOREA GAS UTILIZATION STUDY Economic Cost of LNG Supply Scenario .A. :KYONGIN AREA I ncrementa l start i ng i n 1 990 LNG Pri ce 1 ( LNG F08 90% Crude Oi l) I I L N G SUPPLY . G A S V A L U E .L N G .ECONOMIC I I .RESIDENT. POIWER . SUPPLY .BENEFIT I ITotal Increm. . INDUSTRY TOTAL . COST . I I I 1000 Tons/Y . M i l l i o n U S $ . Mill. S. Mill. $ I 1 1989 1 2000 2000 . 54.7 26.9 377.4 459.0 . I I1990 1 2000 0 . 23.6 11.2 -3.3 31.5 79.1 -47.5 1 1 1991 1 2000 -O . 51.0 24.1 -8.3 66.8 126.3 -59.6 1 1 1992 1 2500 500 . 74.3 36.4 129.7 240.5 286.8 -46.3 1 ! 1993 1 2940 940 95.6 49.0 262.4 407.0 393.5 13.5 1 1 1994 1 3400 1400 117.8 57.2 406.7 581.7 475.4 106.3 1 11995 1 3900 1900 141.3 65.9 537.2 744.4 600.2 144.3 1 ! 1996 1 4000 2000 170.0 74.7 558.6 803.3 641.6 161.6 i 11997 1 4400 2400 202.5 83.5 664.8 950.8 709.1 241.7 1 ! 1998 1 4800 2800 239.7 90.1 790.3 1120.1 785.6 334.5 1 ! 1999 1 5100 3100 279.4 97.5 873.3 1250.2 881.9 368.3 1 ! 2000 1 4950 2950 321.4 106.3 798.9 1226.6 865.3 361.3 1 ! 2001 1 5100 3100 364.6 117.9 813.3 1295.8 935.3 360.6 1 ! 2002 1 5450 3450 407.6 125.6 923.3 1456.4 1050.5 405.9 1 I 2003 i 5750 3750 444.0 132.1 984.0 1560.1 1151.1 409.0 1 I2004 1 6350 4350 480.5 138.5 1163.4 1782.4 1320.2 462.2 1 12005 1 6350 4350 516.4 145.4 1125.6 1787.4 1302.6 484.8 1 1 2006 1 6450 4450 552.8 152.0 1120.6 1825.4 1311.5 513.9 1 1 2007 1 6450 4450 588.6 156.1 1086.1 1830.8 1304.0 526.8 1 -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Present Value at d.r. Total 13 p.cent Resident.Industry Power Value Cost Benefit US $/GCal 30.59 22.96 34.93 32.17 25.48 6.69 US $/MMBTU 7.71 5.79 8.80 8.11 6.42 1.69 W o n / M3 222.1 166.7 253.6 233.6 185.0 48.6 Mill.US$ 1229 452 3096 4777 3784 993 Billion M3 3.65 1.79 8.06 13.50 13.50 13.50 Presenx Value at d.r. 8 p.cent US $/GCaI 30.7P 23.32 28.73 28.60 24.72 3.89 US $/MMBTU 7.76 5.88 7.24 7.21 6.23 0.98 W o n / M3 223.4 169.3 208.6 207.7 179.4 28.2 Mill.US$ 2005 705 4184 6894 5957 937 Billion M3 5.92 2.75 13.24 21.91 21.91 21.91 Annex 12 - 151 - Page 2 of 10 E C O N OM I C C O S T O F L N G S U P P L Y S c e n a r i o . A . :K Y O N G I N A R E A L N G P r i c e 1 ( L N G F OB 9 0 % C r u d e O i l) I I L N G SUPPLY .L N G COST CIF . INFRASTRUCTURE .L N G I I I . .Pipes Distribution . SUPPLY I ITotal Increm. . Incremental .Terminal . COST I I _ _ __I-- - - - - - - - - - - - - - - - - I I 1000 Tons/Y . $/MMBTU Mill. $ . Million S . Mill. S ' I__ __I ____ __ _------ -I 1 1989 1 2000 2000 . 3.53 364.3 . I I 1990 1 2000 0 . 3.82 0.1 6.5 72.5 79.1 1 1 1991 1 2000 -O . 3.91 -0.1 51.1 75.3 126.3 1 11992 1 2500 500 . 4.01 103.5 105.6 77.7 286.8 1 11993 1 2940 940 4.10 198.7 122.9 71.8 393.5 1 1 1994 I 3400 1400 4.20 303.4 111.6 60.5 475.4 1 11995 1 3900 1900 4.34 425.4 110.0 64.8 600.2 1 1 1996 1 4000 2000 4.48 462.3 105.9 73.3 541.6 1 1 1997 1 4400 2400 4.62 572.1 58.4 78.7 709.1 1 11998 1 4800 2800 4.77 689.2 15.9 80.6 785.6 1 11999 1 5100 3100 4.87 778.8 9.6 93.5 881.9 1 1 2000 1 4950 2950 4.96 755.0 9.6 100.7 865.3 1 1 2001 1 5100 3100 5.06 809.4 16.9 108.9 935.3 1 12002 1 5450 3450 5.16 918.5 31.7 100.2 1050.5 1 I 2003 I 5750 3750 5.16 998.3 49.0 103.8 1151.1 I 1 2004 1 6350 4350 5.16 1158.2 56.0 106.0 1320.2 1 I2005 1 6350 4350 5.16 1158.1 36.0 108.5 1302.6 1 1 2006 1 6450 4450 5.16 1184.8 15.5 111.2 1311.5 1 1 2007 1 6450 4450 5.16 1184.8 12.1 107.0 1304.0 1 -- Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL 13 p.cent Pipeline COST US $/GCal 18.95 2.84 9.17 25.48 US $/MMBTU 4.77 0.72 2.31 6.42 W o n I M3 137.5 20.6 66.6 185.0 Mill.US$ 2813 422 549 3784 Billion M3 13.50 13.50 5.44 13.50 Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL 8 p.cent Pipeline COST US S/GCal 19.21 2.28 8.15 24.72 US $/MMBTU 4.84 0.57 2.05 6.23 W o n I M3 139.5 16.6 59.2 179.4 Mill.US$ 4630 550 778 5957 Billion M3 21.91 21.91 8.67 21.91 12 Page 3 of 10 - 152 - E C O N O M I C B E H E F I T O f G A S U T I L I Z A T I O N S c e n a r i o B : K Y O N G I N + C H U N G C H O N G A R E A I n c r e m e n t a l s t a r t i n g i n 1 9 9 0 L N G P r i c e 1 ( L N G F 0 9 0 % C r u d e 0 1 ) I I L N G SUPPLY G A S V A L U E L N G .ECONOMIC I t I .RESTOENT. POWER . SUPPLY .BENEFIT I ITotal Increm. . INDUSTRY TOTAL . COST . I I l__ I _ ___--- ---_---- -- --_-- - - -I I 1000 Tons/Y . M 1 1 o n U S $ . Hill. $. Mill. $ I I _ l _ I--- -- --- -- -- --- -- -- --- -- -- --- -- --- -- -- --- -- -- --- -- -- 1 1989 1 2000 2000 . 54.7 26.9 377.4 459.0 . I i1990 I 2000 0 . 23.6 11.2 -3.3 31.5 79.1 -47.5 1 11991 1 2000 -O . 51.0 24.1 -8.3 66.8 144.9 -78.1 I 11992 I 2500 500 . 74.3 36.4 129.7 240.5 324.3 -83.9 1 11993 I 3000 1000 112.8 53.5 262.4 428.6 471.4 -42.8 I 1 1994 1 3500 1500 140.3 63.0 412.5 615.8 502.7 113.2 1 11995 i 4000 2000 170.7 73.9 536.1 780.6 632.2 148.4 I 11996 I 4150 2150 209.3 84.6 562.4 856.4 694.2 162.1 I 1 1997 1 4600 2600 248.4 94.6 678.5 1021.6 761.8 259.8 I I 1998 I 5000 3000 296.3 103.4 794.1 1193.8 847.6 346.2 1 I 1999 1 5400 3400 346.4 112.0 899.9 1358.3 967.5 390.8 1 I 2000 1 5400 3400 402.1 122.2 861.8 1386.2 995.1 391.1 1 t 2001 1 5450 3450 462.6 135.3 830.4 1428.2 1046.1 382.2 1 I 2002 I 5800 3800 521.6 144.5 927.2 1593.3 1162.5 430.8 1 1 2003 1 6150 4150 573.1 152.1 991.1 1716.3 1277.0 439.3 1 1 2004 1 7000 5000 625.2 159.7 1238.5 2023.4 1514.0 509.3 I I 2005 I 7000 5000 676.3 168.1 1186.5 2030.9 1496.9 534.0 I I 2006 I 7100 5100 727.6 176.0 1168.1 2071.6 1505.4 566.2 1 12007 1 7100 5100 776.9 181.6 1120.7 2079.3 1497.4 581.8 1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Present Value at d.r. Total 13 p.cent Resident.Industry Power Value Cost Benefit US $/GCal 30.76 22.77 34.60 31.83 25.75 6.08 US $/MMBTU 7.75 5.74 8.72 8.02 6.49 1.53 W o n / M3 223.3 165.3 251.2 231.1 186.9 44.1 Hill.US$ 1517 507 3168 5192 4200 992 Billion M3 4.48 2.02 8.32 14.83 14.83 14.83 ilresent Value at d.r. 8 p.cent US S/GCal 30.93 23.10 28.58 28.59 24.91 3.68 US $/KNBTU 7.79 5.82 7.20 7.20 6.28 0.93 W o n / M3 224.6 167.7 207.5 207.5 180.8 26.7 Mill.US$ 2504 796 4310 7611 6631 980 Billion H3 7.36 3.13 13.71 24.20 24.20 24.20 Page 4 of 10 - 153 - E C ON NO M I C C O S T O F L N G S U P P L Y S c e n a r i o B : K Y O N G I N + C H U N G C H O N G A R E A L N G P r i c e 1 ( L NG F O B 9 0 C r u de O I ) I I L N G SUPPLY .L N G COST CIF . INFRASTRUCTURE .L N G I I .Pipes Distribution . SUPPLY I I ITotal Increm.. Incremental .Terminal . COST I ___ _ I----------------------------------------------------------------------- _-I I I 1000 Tons/Y . $/MMBTU Mill. $ . Nillion $ . Mill. $ I __ __ I------------ ----------- ----------- ------------ ----------- ----------- I 1989 1 2000 2000 . 3.53 364.3 I I 1990 1 2000 0 . 3.82 0.1 6.5 72.5 79.1 I 11991 1 2000 -0 . 3.91 -0.1 69.7 75.3 144.9 1 I 1992 I 2500 500 . 4.01 103.5 143.1 77.7 324.3 I 11993 I 3000 1000 4.10 211.5 160.4 99.5 471.4 1 11994 I 3500 1500 4.20 325.0 111.6 66.0 502.7 1 1 1995 I 4000 2000 4.34 447.9 110.0 74.3 632.2 I 11996 I 4150 2150 4.48 497.0 110.9 86.2 694.2 I 11997 I 4600 2600 4.62 619.8 58.4 83.6 761.8 1 I 1998 I 5000 3000 4.77 738.2 15.9 93.5 847.6 I 11999 1 5400 3400 4.87 854.3 9.6 103.6 967.5 1 ! 2000 I 5400 3400 4.96 870.1 9.6 115.4 995.1 1 1 2001 1 5450 3450 5.06 900.8 16.9 128.4 1046.1 1 I 2002 I 5800 3800 5.16 1011.7 31.7 119.1 1162.5 I I 2003 I 6150 4150 5.16 1105.0 49.0 123.0 1277.0 I ! 2004 I 7000 5000 5.16 1331.2 56.0 126.8 1514.0 I I 2005 I 7000 5000 5.16 1331.1 36.0 129.8 1496.9 1 I 2006 I 7100 5100 5.16 1357.9 15.5 132.0 1505.4 I I 2007 I 7100 5100 5.16 1357.8 12.1 127.5 1497.4 I -------- ------- ------- ------- ------- ------- ------- ------- ------- ------- Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL 13 p.cent Pipeline COST US $/GCal 18.99 2.99 8.59 25.75 US S/MNBTU 4.79 0.75 2.16 6.49 W o n / M3 137.9 21.7 62.4 186.9 Mill.US$ 3097 488 615 4200 Billion M3 14.83 14.83 6.51 14.83 Present Value at d.r. LNG CIF TERNINAL DISTRIB. LNG TOTAL 8 p.cent Pipeline COST US $/GCal 19.25 2.35 7.62 24.91 US $/MMBTU 4.85 0.59 1.92 6.28 W o n / M3 139.7 17.1 55.4 180.8 Mill.US$ 5125 626 880 6631 Billion M3 24.20 24.20 10.49 24.20 Page 5 of 10 - 154 - E CONOM I C BE NE F I T OF GAS UT I L I ZAT I ON Scenario C :KYONGIN/ CHUNGCHONG/YONGNAN I n c r e m e n t a l s t a r t 1 n g i n 1 9 9 0 L N G P r i c e 1 ( L NG F O B 9 0 % C r u de O i ) I I L N G SUPPLY G A S V A L U E . L N G.ECONOMIC I I I .RESIDENT. POWER . SUPPLY .BENEFIT I I ITotal Increm. . INDUSTRY TOTAL . COST . I _ __ I------------------ ------------------ ------------------ --------------- -I I I 1000 Tons/Y . M i i o n U S $ . Nill. $. Hill. $ I _ _ _I------ ------ ------ ----- ------ ------ ------ ----- ------ ------ ----- 1 1989 1 2000 2000 . 54.7 26.9 377.4 459.0 . I I 120 1 2000 -O . 23.6 11.2 -3.4 31.4 88.8 -57.4 1 I 1991 1 2000 -O . 51.0 24.1 -8.2 66.8 169.3 -102.5 1 1 1992 1 2500 500 . 74.3 36.4 129.7 240.5 351.0 -110.5 I 1 1993 1 3000 1000 114.3 53.5 262.3 430.0 563.6 -133.6 1 1 1994 1 3500 1500 142.0 63.0 412.5 617.6 622.3 -4.7 1 1 1995 1 4000 1999 172.6 73.9 535.8 782.2 736.6 45.6 1 1 1996 1 4400 2400 269.1 113.6 554.3 937.0 867.2 69.8 1 11997 1 4900 2900 320.5 130.3 669.7 1120.4 834.5 285.9 1 11998 1 5400 3400 383.8 146.2 798.1 1328.0 982.3 345.7 1 I 1999 1 5800 3800 451.7 163.6 880.9 1496.1 1126.7 369.5 1 1 2000 1 5800 3800 527.9 184.3 816.1 1528.3 1178.9 349.4 1 1 2001 1 610C 4100 613.3 209.9 832.5 1655.6 1317.9 337.7 1 1 2002 1 6500 4500 696.2 231.2 915.3 1842.7 1441.0 401.7 1 1 2003 1 7000 4999 769.9 250.1 997.4 2017.4 1560.4 457.0 1 1 2004 1 7900 5900 844.2 268.5 1231.1 2343.8 1784.3 559.5 1 1 2005 1 7900 5899 917.2 287.9 1148.8 2353.9 1785.4 568.5 1 1 2006 1 8200 6200 991.1 306.9 1165.2 2463.2 1870.4 592.8 1 1 2007 1 8200 6200 1062.5 323.4 1087.7 2473.6 1866.5 607.0 1 ------ ----- ----- ----- ------ ----- -- -- ----- ------ ----- ----- ----- ----- Present Value at d.r. Total 13 p.cent Resident.Industry Power Value Cost Benefit US $/GCal 30.60 22.57 34.77 31.29 27.28 4.02 US S/MBTU 7.71 5.69 8.76 7.89 6.87 1.01 W o n / M3 222.1 163.9 252.4 227.2 198.0 29.1 Mill.USS 1905 697 3133 5735 5000 736 Billion M3 5.66 2.81 8.19 16.66 16.66 16.66 Present Value at d.r. 8 p.cent US $/GCal 30.73 22.81 28.65 28.40 26.20 2.20 US $/NMBTU 7.74 5.75 7.22 7.16 6.60 0.56 W o n / M3 223.1 165.6 208.0 206.2 190.2 16.0 Mill.US$ 3201 1139 4251 8591 7924 667 Billion N3 9.47 4.54 13.49 27.50 27.50 27.50 'age i) of 10 - 155 - E C O N OM I C C O S T O F L N G S U P P L Y S c e n a r i o C : K Y 0 N G I N / C H U N G C H O N G / Y O N G N A M L N G P r i c e I ( L N G F O B 9 0 % C r u d e Oi il ) I L N G SUPPLY .L N G COST CIF . INFRASTRUCTURE .L N G I I I .Pipes Distribution . SUPPLY I ITotal Increm. . Incremental .Terminal . COST I I ____I- I I I 1000 Tons/Y . $/MMBTU Mill. S . Million $ . Mill. S I l I - _ I____-_ -_ -_ -_ - _-_-_-_-__-_-_-____-_-_-_- _-- 1 1989 I 2000 2000 3.53 364.3 I I 1990 1 2000 -0 . 3.82 -0.1 16.4 72.5 88.8 1 11991 1 2000 -O . 3.91 -0.0 94.1 75.3 169.3 1 11992 1 2500 500 . 4.01 103.5 169.8 77.7 351.0 1 1 1993 1 3000 1000 4.10 211.5 252.7 99.5 563.6 1 11994 1 3500 1500 4.20 325.1 231.1 66.2 622.3 1 11995 1 4000 1999 4.34 447.7 214.7 74.2 736.6 1 I1996 1 4400 2400 4.48 554.7 65.4 247.1 867.2 1 11997 1 4900 2900 4.62 691.3 24.4 118.9 834.5 1 11998 1 5400 3400 4.77 836.8 11.6 133.9 982.3 1 11999 1 5800 3800 4.87 954.7 18.9 153.0 1126.7 1 1 2000 1 5800 3800 4.96 972.6 33.7 172.6 1178.9 1 1 2001 1 6100 4100 5.06 1070.5 51.0 196.4 1317.9 1 I 2002 1 6500 4500 5.16 1198.0 58.0 184.9 1441.0 1 1 2003 1 7000 4999 5.16 1331.0 38.0 191.4 1560.4 1 I 2004 1 7900 5900 5.16 1570.7 17.5 196.0 1784.3 1 I 2005 1 7900 5899 5.16 1570.6 14.1 200.7 1785.4 1 1 2006 1 8200 6200 5.16 1650.6 14.1 205.7 1870.4 1 1 2007 1 8200 6200 5.16 1650.6 14.1 201.8 1866.5 1 Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL 13 p.cent Pipeline COST US $/GCal 19.08 3.73 8.80 27.28 US S/MMBTU 4.81 0.94 2.22 6.87 W o n l M3 138.5 27.1 63.9 198.0 Mill.US$ 3497 683 819 5000 Billion M3 16.66 16.66 8.47 16.66 Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL 8 p.cent Pipeline COST US $/GCal 19.33 2.85 7.89 26.20 US $/MMBTU 4.87 0.72 1.99 6.60 W o n l M3 140.3 20.7 57.3 190.2 Nill.USS 5847 861 1216 7924 Billion M3 27.50 27.50 14.01 27.50 12 Page 7 of 10 - 156 - E C O N OM I C 8 E N E F I T O F G A S U T I L I Z A T I O N S c e n a r i o C 1. : KY ONG IN/ CHUNG CHO NG/ Y ONG NAN I n c r e m e n t a l s t a r t i n g i n 1 9 9 0 L N G P r I c e 1 ( L NG F O B 9 0 % C r u de O i ) I_-- _-- - -- - -- -- - -- - -- - -- - -- -- - -- - -- - -- -- - _- - -- - -- - I L N G SUPPLY . G A S V A L U E . L N G .ECONOMIC I I .RESIDENT. POWER . SUPPLY .BENEFIT I I ITotal Increm. . INDUSTRY TOTAL . COSI . I I _ _ ___I_ _.__-- -- -I I I 1000 Tens/Y . Mi i o n U S $ . Mill. $. Mill. $ ' I __ _ I----- ---- ----- ---- ---- ----- ---- ---- ----- ---- ---- ----- ---- -- -I 11989 I 2000 2000 . 54.7 26.9 377.4 459.0 . I 11990 I 2000 -O . 23.6 11.2 -3.4 31.4 88.8 -57.4 I 11991 1 2000 -O . 51.0 24.1 -8.2 66.8 169.3 -102.5 I 11992 I 2500 500 . 74.3 36.4 129.7 240.5 351.0 -110.5 I I 1993 I 3000 1000 114.3 53.5 262.3 430.0 563.6 -133.6 I 11994 I 3500 1500 142.0 63.0 412.5 617.6 622.3 -4.7 I 11995 I 4000 1999 172.6 73.9 535.8 782.2 736.6 45.6 I I 1996 I 5000 2999 269.1 113.6 762.1 1144.8 1005.8 139.0 I 11997 I 5000 3000 320.5 130.3 728.0 1178.7 858.2 320.5 I 11998 1 6000 4000 383.8 146.2 1023.5 1553.4 1129.9 423.5 1 11999 I 7000 5000 451.7 163.6 1295.5 1910.7 1434.8 475.9 I I 2000 I 7000 5000 527.9 184.3 1233.7 1945.9 1505.2 440.7 I I 2001 I 7000 5000 613.3 209.9 1155.3 1978.5 1580.2 398.3 I I 2002 I 8500 6500 696.2 231.2 1601.1 2528.5 1990.5 538.0 1 I 2003 1 8500 6500 769.9 250.1 1518.8 2538.8 1966.4 572.4 I I 2004 I 9500 7500 844.2 268.5 1785.4 2898.1 2210.3 687.8 I I 2005 1 9500 7500 917.2 287.9 1703.0 2908.1 2212.7 695.4 I I 2006 I 10000 8000 991.1 306.9 1785.4 3083.3 2351.0 732.3 I I 2007 I 10000 8000 1062.5 323.4 1707.7 3093.6 2347.0 746.6 I ---------------------------------------- --------------------------------------- Present Value at d.r. Total 13 p.cent Resident.Industry Power Value Cost Benefit US $/GCal 30.60 22.57 32.46 30.56 26.08 4.48 US $/HMBTU 7.71 5.69 8.18 7.70 6.57 1.13 W o n / M3 222.1 163.9 235.7 221.9 189.3 32.5 Mill.US$ 1905 697 4171 6774 5780 993 Billion M3 5.66 2.81 11.68 20.15 20.15 20.15 Present Value at d.r. 8 p.cent US $/GCal 30.73 22.81 26.92 27.43 25.13 2.30 US $/MMBTU 7.74 5.75 6.78 6.91 6.33 0.58 W o n / M3 223.1 165.6 195.4 199.2 182.4 16.7 Mill.US$ 3201 1139 5843 10184 9328 855 Billion M3 9.47 4.54 19.74 33.75 33.75 33.75 Page 8 of 10 - 157 - ECONOMIC C0ST OF LNG SUPPLY S c e n a r io C1. :KYONGIN/ CHUNGC HONG/YONGNAM LNG P r i c e 1 (LNG F O B 9 0 % C r u d e O I ) I L N G SUPPLY .L N G COST CIF . INFRASTRUCTURE . L N G I I I .Pipes Distribution . SUPPLY I I ITotal Increm. . Incremental .Terminal . COST I _ _I-- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- - I 1000 Tons/Y . S/MMBTU Mill. $ . Million s . Mill. S I I I - I 1989 I 2000 2000 . 3.53 364.3 . I 1990 1 2000 -0 . 3.82 -0.1 16.4 72.5 88.8 I I 1991 I 2000 -O . 3.91 -0.0 94.1 75.3 169.3 I I 1992 I 2500 500 . 4.01 103.5 169.8 77.7 351.0 I I 1993 I 3000 1000 4.10 211.5 252.7 99.5 563.6 I I 1994 I 3500 1500 4.20 325.1 231.1 66.2 622.3 I 11995 I 4000 1999 4.34 447.7 214.7 74.2 736.6 I ; 1996 I 5000 2999 4.48 693.3 65.4 247.1 1005.8 I 11997 I 5000 3000 4.62 715.0 24.4 118.9 858.2 I I 1998 I 6000 4000 4.77 984.4 11.6 133.9 1129.9 I 11999 I 7000 5000 4.87 1256.4 25.4 153.0 1434.8 I ; 2000 I 7000 5000 4.96 1279.6 53.0 172.6 1505.2 1 I 2001 I 7000 5000 5.06 1305.3 78.4 196.4 1580.2 I I 2002 I 8500 6500 5.16 1730.4 75.2 184.9 1990.5 I I 2003 I 8500 6500 5.16 1730.5 44.5 191.4 1966.4 I I 2004 I 9500 7500 5.16 1996.7 17.5 196.0 2210.3 I I 2005 I 9500 7500 5.16 1996.6 15.4 200.7 2212.7 I 1 2006 I 10000 8000 5.16 2129.9 15.4 205.7 2351.0 I I 2007 1 10000 8000 5.16 2129.8 15.4 201.8 2347.0 I --- Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL 13 p.cent Pipeline COST US S/GCal 19.22 3.16 8.80 26.08 US S/MMBTU 4.84 0.80 2.22 6.57 IW o n / M3 139.5 23.0 63.9 189.3 Mill.USS 4259 702 819 5780 Billion M3 20.15 20.15 8.47 20.15 Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL 8 p.cent Pipeline COST US $/GCal 19.45 2.40 7.89 25.13 US $/MMBTU 4.90 0.61 1.99 6.33 W o n / M3 141.2 17.5 57.3 182.4 M1ll.US$ 7220 892 1216 9328 Billion M3 33.75 33.75 14.01 33.75 Page 9 of 10 - 158 - ECONOMIC BENEF IT OF GAS UTIL I ZATION KYONGIN/ CHUNGCHONG/YONGNAM/HONAM- Scen. D Incremental starting in 1990 NG Pr i ce 1 ( LNG FOB 90% Crude 0 1i I I I L N G SUPPLY , G A S V A L U E L N G ECONOMIC I I I .RESIDENT. POWER . SUPPLY .BENEFIT I ITotal Increm. . INDUSTRY TOTAL . COST . I I _ _ _I----- ---- ----- ---- ---- ----- ---- ---- ----- ---- ---- ----- ---- -- -I I I 1000 Tons/Y M i I i o n U S $ . Mill. $. N1ll. $ I I _ I------ ------ ------ ------ ------ ----- ------ ------ ------ ------ --- -I 1 1989 1 2000 2000 . 54.7 26.9 377.4 459.0 , I I 1990 1 2000 -0 . 23.6 11.2 -3.4 31.4 88.8 -57.4 I 11991 1 2000 -O . 51.0 24.1 -8.2 66.8 169.3 -102.5 1 I 1992 1 2500 500 . 74.3 36.4 129.7 240.5 351.0 -110.5 I 11993 1 3000 1000 114.3 53.5 262.3 430.0 589.6 -159.6 1 1 1994 1 3500 1500 142.0 63.0 412.5 617.6 697.1 -79.5 i 11995 1 4000 1999 172.6 73.9 535.8 782.2 834.2 -52.0 1 11996 1 4500 2500 282.3 123.5 561.4 967.2 980.7 -13.5 1 11997 1 5000 3000 338.9 143.2 669.8 1151.9 875.1 276.8 I I 1998 I 5500 3499 410.6 163.0 787.2 1360.7 1029.8 330.9 1 11999 1 6000 4000 491.1 183.7 887.7 1562.5 1206.4 356.2 1 1 2000 1 6000 4000 581.1 211.3 804.6 1596.9 1268.2 328.7 1 I 2001 1 6400 4400 685.1 246.4 827.8 1759.4 1447.4 312.0 I I 2002 I 7000 5000 780.3 273.8 960.8 2014.9 1608.9 406.0 I 1 2003 1 7400 5400 865.3 298.4 994.1 2157.9 1703.1 454.7 1 1 2004 1 8400 6400 951.0 322.4 1245.0 2518.4 1952.5 565.9 1 1 2005 I 8400 6400 1035.6 347.8 1146.5 2529.8 1957.4 572.4 1 1 2006 1 8900 6899 1120.8 372.3 1213.0 2706.1 2095.1 611.1 I 1 2007 1 8900 6900 1203.7 394.6 1119.6 2717.9 2092.7 625.2 1 ----- ----- ----- ----- ------ ----- ----- ----- ------ ----- ----- ----- ----- Present Value at d.r. Total 13 p.cent Resident.Industry Power Value Cost Benefit US $/GCal 30.49 22.52 34.69 31.03 28.03 3.00 US S/MMBTU 7.68 5.68 8.74 7.82 7.06 0.76 W o n / H3 221.4 163.5 251.9 225.3 203.5 21.8 Mill.US$ 2069 784 3150 6003 5423 580 Billion M3 6.17 3.17 8.26 17.59 17.59 17.59 Present Value at d.r. 8 p.cent US $/GCal 30.61 22.74 28.62 28.28 26.85 1.44 US S/NMBTU 7.71 5.73 7.21 7.13 6.76 0.36 W o n / M3 222.2 165.1 207.8 205.3 194.9 10.4 Nill.USS 3504 1298 4286 9088 8625 462 Billion M3 10.41 5.19 13.61 29.21 29.21 29.21 12 Page 10 of 10 - 159 - E C O N OM I C C O S T O F L N G S U P P L Y S c e n a r i o D KYONGIN/ CHUNGCHONG/YONGNAM/HONAM L N G P r i c e I ( L NG F OB 9 0 % C r u de 0 l) I I L N G SUPPLY .L N G COST CIF . [lFRASTRUCTURE .L N G I I I . .Pipes Distribution . SUPPLY I I ITotal Increm. . Incremental .Termina! . COST I I I 1000 Tons/Y . S/MMBTU Mill. $ . Million $ . Nill. $ I I 1989 1 2000 2000 . 3.53 364.3 .I I 1990 1 2000 -0 . 3.82 -0.1 16.4 72.5 88.8 I 11991 1 2000 -0 . 3.91 -0.0 94.1 75.3 169.3 1 1IM 1 2500 500 . 4.01 103.5 169.8 71.7 351.0 1 1 1993 1 3000 1000 4.10 211.5 278.7 99.5 589.b I 1 1994 1 3500 1500 4.20 325.1 305.9 66.2 697.1 1 1 1995 1 4000 1999 4.34 447.7 312.3 74.2 834.2 1 1 1996 1 4500 2500 4.48 577.8 111.6 291.2 980.7 1 11997 1 5000 3000 4.62 715.2 25.7 134.3 875.1 1 1 1998 1 5500 3499 4.77 861.2 12.9 155.7 1029.8 1 11999 1 6000 4000 4.87 1005.0 20.2 181.2 1206.4 1 1 2000 1 6000 4000 4.96 1023.7 35.0 209.5 1268.2 1 1 2001 1 6400 4400 5.06 1148.8 52.3 246.3 1447.4 I 1 2002 1 7000 5000 5.16 1331.1 59.3 218.4 1608.9 1 1 2003 1 7400 5400 5.16 1437.6 39.3 226.3 1703.1 1 1 2004 1 8400 6400 5.16 1703.8 17.4 231.3 1952.5 1 1 2005 1 8400 6400 5.16 1703.8 15.4 238.2 1957.4 1 1 2006 1 8900 6899 5.16 1836.9 15.4 242.8 2095.1 1 1 2007 1 8900 6900 5.16 1836.9 15.4 240.4 2092.7 1 1-------------------------------------------------------------------------------- Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL 13 p.cent Pipeline COST US $/GCal 19.13 4.18 8.90 28.03 US $/MNBTU 4.82 1.05 2.24 7.06 W o n / M3 138.9 30.4 64.6 203.5 Mil .US$ 3701 809 914 5423 Billion M3 17.59 17.59 9.33 17.59 Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL 8 p.cent Pipeline COST US SIGCal 19.38 3.19 8.02 26.85 US $/JNBTU 4.88 0.80 2.02 6.76 W o n 1 M3 140.7 23.1 58.2 194.9 Mill.USS 6225 1024 1376 8625 Billion M3 29.21 29.21 15.59 29.21 - 160- 13 KOREA GAS UTILIZATION STUDY AIR POLLUTION EMISSIONS FROM ENERGY USE An important perspective in looking at present levels of air pollution in Korea is provided by an examination of the relative as well as absolute pollution or emission intensity of each fuel together with the current and future role of these fuels in the Korean energy balance. Tables 1 and 2, drawn from various sources, present some figures on the former. Table 1: -2 - Uncontrolled Emissions for Selected Fuels Lower Heating Value S02 Emissions Sulfur -------_--- --------------------------- Fuels Content (kcal/ unit) (lb SO /unit) (g 502(Gcal) Natural Gas 0.02 11,000 /cum 0.0 tlO^6 cft 0 Bunker C 1.6Z 9,400 /liter 251.2 /1000 gal 3,204 Bunker C 2.5Z 9,400 /liter *92.5 (1000 gal 5,006 Bunker C 4.0Z 9,400 iliter 628.0 t1000 gal 8,009 Imported Coal 0.72 6,300 /kg 26.6 /ton 2,111 Coal Briquettes 2.OZ* 4,167 /kg 76.0 (ton 9,119 Diesel - stationary 0.42 8,720 /liter 56.8 /1000 gal 781 Diesel - mobile 8,720 (liter 27.0 11000 gal 371 Gasoline - mobile 7,867 /liter 5.0 /1000 gal 76 * mission estimate. Table 2: NOx - Uncontrolled Emissions for Selected Fuels Lower Heating Value NOx Emissions Fuels (kcall unit) (lb NOx /unit) (g NOx/Gcal) Natural Gas households 11,000 /cum 50 110^6 cft 73 commercial 11,000 /cum 100 /10^6 cft 146 industry 11,000 /cum 230 110^6 cft 335 utility 11,000 /cum 390 110^6 cft 568 Bunker C industry 9,400 /liter 40 /1000 gal 510 Bunker C utility 9,400 /liter 105 11000 gal 1,339 Imported Coal indlutil 6,300 /kg 18 (ton 1,429 Coal Briquettes hshldlcom 4,167 /kg 6 (ton 720 Diesel - stat. hshld/com 8,720 /liter 12 ('000 gal 165 Diesel - mobile transport 8,720 (liter 370 !'000 gal 5,087 Gasoline - m.obile transport 7,867 /liter 183 /'000 gal 2,789 [ORD 21915 U.S.S.R. 128' - 131' C H I N DEMOCRATIC PEOPLE'S REPUBLIC OF KOREA - -> - _ _ . ~ ~ ~ _ _ 32'30 3r30- REP OF KOREA I 131' Rfp or KoRIA JAPAN gCunchon 38' % ~~~~~0 t lsan Sanggye _________________________ TERMINAL SEOUL Tonghae Inchon :P n nogchon undang PYONC1AFK ogtaek -.3" 3r 1W&i taj 0Chungiu Onyan Chngju Pohang Q< 36'~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~6 ri~~~~~~~~~~~~ag Masai! ' i>Ulsan f 2 AW J~~~~~~~~~~CiIn°w] usan Mokpo rERMN REPUBLIC OF KOREA PROPOSED GAS SYSTEM - Existing Pipe Line Planned Pipe Lines A Gas Terminal 34 -4 1 .j, Major Ports o Selected Cities Urban Areas Provinre Boundaries Cheju LME ;,- ve 0 20 40 60 0 100 120 140 160 0 20 40 60 sO 100 tMILES 125s 138' 127' 128' 128't OCTOBER 1989 IBRD 21983R 'IO llsan Sanggye No ~~~~~b Bundang )\>L1014' .SEA (-N t ...........SUWON CITY Suwan REPUBLIC OF KOREA PROPOSED GAS SYSTEM Seoul Metropolitan Area and Vicinities -PROPOSED PIPELINES -EXISTING PIPELINES / PROPOSED GAS TERMINAL f 4/ ON(~~~~~~~~ A E~~~~~~~XISTING GAS TERMINAL 0 SELECTED CITIES URBAN AREAS Y0LA(.lL.K d 9 KY( \ EPBLCOFKOE NDO Cl-I~~~ ~ ~~ L EXSTN PP-IE vi} !O\GNM l V < PyongtaeL 00 CHOUA8Ur SNTE A rzo 1.'. f

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FAQs

Cng Is A Readily Available Alternative To _________.? ›

CNG is a readily available alternative to gasoline made by compressing natural gas to less than 1% of its volume at standard atmosphere pressure.

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What is CNG available alternative to? ›

Compressed Natural Gas (CNG) is a gasoline and diesel fuel alternative consisting primarily of methane. The gas is associated with other fossil fuels (coal or oil) and is created by methanogenic organisms in landfills.

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What is CNG gas used for? ›

Compressed natural gas is primarily used as a substitute fuel for powering vehicles. However, it can also be used for power generation, water heating and air conditioning. Compressed natural gas is an alternative fuel that is not only economical but also easily accessible and offers great environmental benefits.

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Why CNG is used as an alternative fuel? ›

Although compressed natural gas is a fossil fuel, it is the cleanest burning fuel at the moment in terms of NO_x and soot (PM) emissions. CNG can be employed to power passenger cars and city busses. CNG passenger vehicles emit 5-10% less CO₂ than comparable gasoline powered passenger vehicles.

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What is the equivalent of CNG to gasoline? ›

One GGE of CNG pressurized at 2,400 psi (17 MPa) is 0.77 cubic feet (22 litres; 5.8 US gallons). This volume of CNG at 2,400 psi has the same energy content as one US gallon of gasoline (based on lower heating values: 148,144 BTU/cu ft (1,533.25 kWh/m³) of CNG and 114,000 BTU/US gal (8.8 kWh/L) of gasoline.

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What vehicles can use CNG? ›

CNG can power almost any size vehicle without losing any power. Transit buses, school buses, refuse trucks, concrete mixers and semi-tractors are examples of heavy duty vehicles that are converting to CNG at a high rate. 1 of every 5 transit buses sold today in the U.S. is running on CNG.

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Can CNG be used as a fuel? ›

Natural gas, a fossil fuel comprised mostly of methane, is one of the cleanest burning alternative fuels. It can be used in the form of compressed natural gas (CNG) to fuel passenger cars and city busses or in the form of liquefied natural gas (LNG) to fuel heavy duty trucks.

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Is CNG is a natural gas? ›

Two forms of natural gas are currently used in vehicles: compressed natural gas (CNG) and liquefied natural gas (LNG). Both are domestically produced, relatively low priced, and commercially available.

How CNG can be the best alternative for petrol? ›

Since CNG is a clean burning fuel, combusting it leaves little or no residue compared to gasoline or diesel. Thus, the damage to the pipes and tubes of the vehicle's engine is greatly reduced. There is also less particulate matter that can contaminate the motor oil.

Is CNG more efficient than gas? ›

Compressed Natural Gas (CNG) saves up to 50% over conventional fuels, and CNG vehicles are available for all types of applications, including business fleets and vehicles for personal use.

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Is CNG fuel cheaper? ›

CNG fuel burns cleaner than gasoline or diesel and reduces emissions significantly. You also don't have to use after-market additives or emissions controls since it's so clean. It's cheaper. CNG fuel is much cheaper than gasoline or diesel fuels.

What is CNG compared to LNG? ›

Compressed Natural Gas, or CNG, and Liquefied Natural Gas, or LNG, are the same substance. CNG is received and stored a vehicle's tank is gaseous form. To obtain LNG, natural gas is compressed and cooled to extremely low temperatures, at which point it turns to liquid.

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Is CNG like propane? ›

CNG is Natural

Compressed natural gas is just that—a natural gas. This means it doesn't need to be created or sourced from anywhere other than the US. Propane is produced through crude oil refinement, so instead of coming from the earth like CNG, it is a byproduct.

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What are the two types of CNG? ›

There are basically two types of classifications that are found in CNG kits:

One, which classifies them as Venturi kits and Sequential kits.
and the other, which classifies them as Open-loop systems and Closed-loop systems.

Apr 13, 2016

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Why does the US not use CNG? ›

Shale Oil Boom

This is the single biggest reason why the CNG car revolution did not take off in the country, like many people predicted. The US is blessed with huge amounts of shale gas deposits and fracking has made it possible to access and extract these reserves with great success.

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Cng Is A Readily Available Alternative To _________. (2023)

1. Why Compressed Natural Gas? - Freedom CNG

2. CNG is a readily available alternative to ______. - CenterStudent

3. CNG is a readily available alternative to gasoline that's made by ...

4. Natural Gas Basics - Alternative Fuels Data Center - Department of Energy

5. cng is a readily available alternative to

6. cng is a readily available alternative to ______.

7. [PDF] Propane, CNG, LNG, and Synthetic Fuels - James Halderman

8. [PDF] Hydrogen/CNG Blended Fuels Performance Testing in a Ford F-150

9. [PDF] department of food and agriculture

10. [PDF] Inspection of Co 1, ressed Natural Gas Cylinders on ichool Buses - NREL

11. [PDF] UC Irvine - eScholarship

12. [PDF] SPECIFICATIONS CONTRACT DOCUMENTS JUNE 17,2013

13. [PDF] FTA Motor Fuel Tax Section Uniformity Project

14. Electricians will sometimes call switches “disconnects” or a ... - Weegy

15. [PDF] AGENDA REPORT - Beverly Hills Climate Action & Adaptation Plan

16. 2023 S/P2 Training Automotive Service Safety Final Exam Answers 1

17. [PDF] EFFECTIVE DATE - PennDOT

18. [DOC] E/ECE/324/Rev - UNECE

19. [PDF] Evaluation of the environmental impact of modem passenger cars ...

20. [PDF] Uniform Laws and Regulations in the Areas of Legal Metrology and Fuel ...

21. [PDF] The Transition to Alternative Fuel Vehicles (AFVs) - CORE

22. [PDF] TAP-CMAQ-Guidebook-Complete ...

23. [PDF] ENERGY POLICY FOR PENNSYLVANIA

24. [PDF] Interconnect Guide for Renewable Natural Gas (RNG) in New York State

25. multi-page.txt - World Bank Documents and Reports

FAQs

Cng Is A Readily Available Alternative To _________.? ›

Is CNG more efficient than gas? ›

References